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INDEX TO FINANCIAL STATEMENTS

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Filed Pursuant to Rule 424(b)(3)
Registration Statement No. 333-207261

         PROSPECTUS

Midstates Petroleum Company, Inc.
Midstates Petroleum Company LLC

Offer to exchange up to

$625,000,000 aggregate principal amount of 10% Senior Secured Second Lien Notes
due 2020 that have been registered under the Securities Act of 1933

for

$625,000,000 aggregate principal amount of 10% Senior Secured Second Lien Notes
due 2020 that have not been registered under the Securities Act of 1933

The exchange offer and withdrawal rights will expire at
5:00 p.m., New York City time, on November 16, 2015 unless extended.

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         We are offering to exchange up to $625,000,000 aggregate principal amount of our new 10% Senior Secured Second Lien Notes due 2020, which have been registered under the Securities Act of 1933, as amended (the "Securities Act"), referred to in this prospectus as the "new notes," for any and all of our outstanding unregistered 10% Senior Secured Second Lien Notes due 2020, referred to in this prospectus as the "old notes." We issued the old notes on May 21, 2015 in a transaction not requiring registration under the Securities Act. We are offering you new notes in exchange for old notes in order to satisfy our obligations from that previous transaction. The new notes will represent the same debt as the old notes and we will issue the new notes under the same indenture as the old notes. The new notes offered hereby, together with any old notes that remain outstanding after the completion of the exchange offer, will be treated as a single class under the indenture governing them. The old notes and the new notes are collectively referred to in this prospectus as the "notes."

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         Please read "Risk Factors" beginning on page 9 of this prospectus for a discussion of factors you should consider before participating in the exchange offer.

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         We will exchange the new notes for all outstanding old notes that are validly tendered and not withdrawn before the expiration of the exchange offer. You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer. The exchange procedure is more fully described in "Exchange Offer—Procedures for Tendering." If you fail to tender your old notes, you will continue to hold unregistered notes that you will not be able to freely transfer.

         The terms of the new notes are substantially identical to the old notes, except that the transfer restrictions, registration rights and provisions for additional interest applicable to the old notes do not apply to the new notes. Please read "Description of New Notes" for more details on the terms of the new notes. We will not receive any cash proceeds from the issuance of the new notes in the exchange offer. The exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes.

         Each broker-dealer that receives new notes for its own account pursuant to this offering must acknowledge that it will deliver this prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of up to 180 days after the exchange date (as such period may be extended), we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. Please read "Plan of Distribution."

         Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

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The date of this prospectus is October 16, 2015.

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        This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, or the "SEC." In making your decision whether to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the letter of transmittal accompanying this prospectus. We have not authorized anyone to provide you with any other information. If you receive any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus or the date of such incorporated documents, as the case may be.

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FORWARD-LOOKING STATEMENTS

        Various statements contained in this prospectus are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements other than statements of historical fact included in this prospectus and any prospectus supplement are forward looking statements, including, without limitation, statements regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management. When used in this prospectus, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this prospectus could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

        Forward-looking statements may include statements about our:

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business strategy;



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estimated future net reserves and present value thereof;



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technology;



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financial condition, revenues, cash flows and expenses;



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levels of indebtedness, liquidity and compliance with debt covenants;



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financial strategy, budget, projections and operating results;



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oil and natural gas realized prices;



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timing and amount of future production of oil and natural gas;



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availability of drilling and production equipment;



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availability of oilfield labor;



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availability of third party natural gas gathering and processing capacity;



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the amount, nature and timing of capital expenditures, including future development costs;



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availability and terms of capital;



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drilling of wells, including our identified drilling locations;



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successful results from our identified drilling locations;



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marketing of oil, natural gas liquids and natural gas;



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the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cash position and levels of indebtedness;



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infrastructure for salt water disposal and electrical power;



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sources of electricity utilized in operations and the related infrastructures;



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costs of developing our properties and conducting other operations;



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general economic conditions;



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effectiveness of our risk management activities;



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environmental liabilities;

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counterparty credit risk;



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the outcome of pending and future litigation;



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governmental regulation and taxation of the oil and natural gas industry;



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developments in oil-producing and natural gas-producing countries;



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uncertainty regarding our future operating results; and



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plans, objectives, expectations and intentions contained in this prospectus that are not historical.

        All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors."

        These factors include:

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variations in the market demand for, and prices of, oil, natural gas liquids and natural gas;



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uncertainties about our estimated quantities of oil, natural gas liquids and natural gas reserves;



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the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;



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access to capital and general economic and business conditions;



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uncertainties about our ability to replace reserves and economically develop our current reserves;



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risks in connection with acquisitions;



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risks related to the concentration of our operations onshore in Oklahoma, Texas and Louisiana;



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drilling results;



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the potential adoption of new governmental regulations;



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possible exposure to additional tax liabilities; and



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our ability to satisfy future cash obligations and environmental costs.

        These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

        Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.

        Reserve engineering is a process of estimating underground accumulations of oil, natural gas liquids and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil, natural gas liquids and natural gas that are ultimately recovered.

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RISK FACTORS

        You should carefully consider the risk factors and all of the other information included in this prospectus and the documents we have filed with the SEC, including those in "Risk Factors," in evaluating an investment in the new notes. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Relating to the Exchange Offer

If you do not properly tender your old notes, you will continue to hold unregistered outstanding notes and your ability to transfer outstanding notes will be adversely affected.

        We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes. Please read "Exchange Offer—Procedures for Tendering" and "Description of New Notes."

        If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates for your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws, or offer and sell under an exemption from these requirements. We do not plan to register any sale of the old notes under the Securities Act. For further information regarding the consequences of failing to exchange your old notes in the exchange offer, please read "Exchange Offer—Consequences of Failure to Exchange."

You may find it difficult to sell your new notes.

        The new notes are a new issue of securities and, although the new notes will be registered under the Securities Act, the new notes will not be listed on any securities exchange. Because there is no public market for the new notes, you may not be able to resell them.

        We cannot assure you that an active market will develop for the new notes or that any trading market that does develop will be liquid. If an active market does not develop or is not maintained, the market price and liquidity of the new notes may be adversely affected. If a market for the new notes develops, they may trade at a discount from their initial offering price. The trading market for the new notes may be adversely affected by:

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changes in the overall market for non-investment grade securities;



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changes in our financial performance or prospects;



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the financial performance or prospects for companies in our industry generally;



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the number of holders of the new notes;



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the interest of securities dealers in making a market for the new notes; and



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prevailing interest rates and general economic conditions.

        Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the new notes, if any, may be subject to similar volatility. Prospective investors in the new notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.

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Some holders who exchange their old notes may be deemed to be underwriters.

        If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the new notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Risks Relating to the Notes

We may not be able to generate sufficient cash flows to service all of our indebtedness, including the notes, our Third Lien Notes, our Senior Unsecured Notes, and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful. If we are unable to repay or refinance our existing and future debt as it becomes due, we may be unable to continue as a going concern.

        Our ability to make scheduled payments on, or to refinance, our debt obligations, including the notes, our Third Lien Notes and our Senior Unsecured Notes, will depend on our financial and operating performance, which is subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. Our existing and future debt agreements could create issues as interest payments become due and the debt matures that will threaten our ability to continue as a going concern. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness, including the notes and our Senior Unsecured Notes, or to fund our other liquidity needs. Our credit facility and the indenture governing the notes restrict our ability to dispose of assets and our use of any of the proceeds. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations and our ability to satisfy our obligations under the notes.

        We have substantial interest payments due during the remainder of 2015. If we cannot make scheduled payments on our debt, we will be in default and, as a result:

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our debt holders could declare all outstanding principal and interest to be due and payable;



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the lenders under our revolving credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and



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we could be forced into bankruptcy or liquidation.

        All of these events could result in you losing your investment in the notes. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient.

        Despite our current level of indebtedness, we may incur substantially more debt in the future, which could further exacerbate the risks described above. Furthermore, we are permitted to incur additional debt, under the terms of the credit agreements governing our credit facility, subject to borrowing base availability, and the indentures governing the notes and our Senior Unsecured Notes, subject to certain limitations, which in each case could intensify the related risks that we and our subsidiary now face. See "Description of New Notes."

        The consolidated financial statements included in this prospectus have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

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We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness.

        Our total consolidated indebtedness consists of $625 million in aggregate principal amount of the notes, $524.121 million in aggregate principal amount of our Third Lien Notes, $293.6 million in aggregate principal amount of our 2020 Senior Notes and $347.7 million in aggregate principal amount of our 2021 Senior Notes. The covenants contained in the agreements governing our outstanding indebtedness, including the indenture for the notes, our Third Lien Notes, our 2020 Senior Notes and 2021 Senior Notes, limit, among other things, our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments. Any borrowings under the revolving credit facility will be secured on a first lien basis, and, as a result, will be effectively senior to the notes and the guarantees of the notes by any guarantors, to the extent of the value of the collateral securing that indebtedness.

        In addition, the holders of any future secured debt we may incur that ranks equally with the notes may be entitled to share with the holders of the notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us. This may have the effect of reducing the amount of proceeds paid to you in such an event. If new debt is added to our current debt levels, the related risks that we now face could intensify.

Our substantial indebtedness, liquidity issues and potential to seek restructuring transactions may have a material adverse effect on our business and operations.

        Our substantial indebtedness, liquidity issues and potential to seek restructuring transactions may result in uncertainty about our business and cause, among other things:

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third parties' to lose confidence in our ability to explore and produce oil and natural gas, resulting in a significant decline in our revenues, profitability and cash flow;



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difficulty retaining, attracting or replacing key employees;



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employees to be distracted from performance of their duties or more easily attracted to other career opportunities; and



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our suppliers, vendors, hedge counterparties and service providers to renegotiate the terms of our agreements, terminate their relationship with us or require financial assurances from us.

        These events may have a material adverse effect on our business and operations.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

        We are subject to interest rate risk in connection with borrowings under our credit facility, which bears interest at variable rates. Interest rate changes will not affect the market value of any debt incurred under such facility, but could affect the amount of our interest payments, and accordingly, our future earnings and cash flows, assuming other factors are held constant. We currently do not have any interest rate hedging arrangements with respect to the credit facility. In the future, we may enter into interest rate swaps that involve the exchange of floating for fixed rate interest payments in order to reduce interest rate volatility; however, any swaps we enter into may not fully mitigate our interest rate risk. A significant increase in prevailing interest rates, which results in a substantial increase in the interest rates applicable to our interest expense could have a material adverse effect on our financial condition and results of operations.

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Our revolving credit facility, the indenture governing the notes and the indenture governing the Third Lien Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

        Our revolving credit facility and the indenture governing our notes includes certain covenants that, among other things, restrict:

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our ability to incur or assume additional debt or provide guarantees in respect of obligations of other persons;



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issue redeemable stock and preferred stock;



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pay dividends or distributions or redeem or repurchase capital stock;



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prepay, redeem or repurchase certain debt;



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make loans and investments;



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create or incur liens;



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restrict distributions from our subsidiaries;



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sell assets and capital stock of our subsidiaries;



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consolidate or merge with or into another entity, or sell all or substantially all of our assets; and



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enter into new lines of business.

        A breach of the covenants under the indenture governing the notes, the revolving credit facility or the indenture governing the Third Lien Notes could result in an event of default under the applicable indebtedness. An event of default may allow the creditors to accelerate the related debt and may result in an acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In addition, an event of default under our credit facility would permit the lenders under the facility to terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our revolving credit facility could proceed against the collateral granted to them to secure that debt.

        In addition, our revolving credit facility requires us to maintain certain financial ratios, including a leverage ratio. All of these restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

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Our level of indebtedness may increase and reduce our financial flexibility.

        In the future, we may incur significant additional indebtedness in order to make future acquisitions or to develop our properties. Our current level of indebtedness could affect our operations in several ways, including the following:

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causing a significant portion of our cash flows to be used to service our indebtedness, thereby reducing the availability of cash flows for working capital, capital expenditures and other general business activities;



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increasing our vulnerability to general adverse economic and industry conditions;



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limiting our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;



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placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, such competitors may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;



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causing our debt covenants to affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;



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making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings;



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impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and



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making it more difficult for us to satisfy our obligations under the indentures governing our Senior Unsecured Notes.

        A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control.

        If we are unable to repay our debt out of our cash on hand, we could attempt to refinance such debt, obtain additional borrowings, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that refinancing, additional borrowings, proceeds from the sale of assets or equity financing will be available to pay or refinance such debt. Factors that may affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions, our market value, our reserve levels and our operating performance at the time of such offering or other financing. The inability to repay or refinance our debt could have a material adverse effect on our operations and could result in a reduction in our capital program or lead us to pursue other alternatives to develop our assets.

        In addition, our bank borrowing base is subject to periodic redeterminations on a semi-annual basis, effective October 1 and April 1 and up to one additional time per six-month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrative agent under our revolving credit facility. In the future we could be forced to repay a portion of our then outstanding bank borrowings due to future redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are unable to arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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We may be unable to maintain compliance with certain financial ratio covenants of our outstanding indebtedness which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

        We are in compliance with our financial covenants; however, we cannot guarantee that we will be able to comply with such terms at all times in the future. Any failure to comply with the conditions and covenants in our revolving credit facility that is not waived by our lenders or otherwise cured could lead to a termination of our revolving credit facility, acceleration of all amounts due under our revolving credit facility, or trigger cross-default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our indebtedness impose on us.

The liens securing the notes and the guarantees are contractually subordinated to our and our guarantors, existing and future obligations under our revolving credit facility and certain other permitted liens to the extent of the value of the collateral securing such obligations.

        The liens securing the indebtedness evidenced by the notes and the guarantees are contractually subordinated, pursuant to the terms of the Intercreditor Agreement, to all of our and the guarantors' existing and future obligations under our revolving credit facility and certain other permitted liens, to the extent of the collateral securing such obligations. Obligations outstanding under our revolving credit facility (including hedges entered into in connection therewith) are secured by a first-priority security interest on the collateral. Although the notes will rank equally in right of payment with all of our existing and future obligations under our revolving credit facility, pursuant to the terms of the Intercreditor Agreement all proceeds of collateral realized after an event of default are required to be applied first to the satisfaction of our priority lien debt until repaid in full.

The value of the collateral securing the notes may not be sufficient to ensure repayment of the notes because the holders of our revolving credit facility debt and other first priority lien obligations will be paid first from the proceeds of the collateral.

        Our indebtedness and other obligations under our revolving credit facility are secured by a first-priority lien on the collateral securing the notes. The liens securing the notes and the guarantees are contractually subordinated to the liens securing obligations under our revolving credit facility and other priority lien obligations, so that proceeds of the collateral will be applied first to repay those obligations before we use any such proceeds to pay any amounts due on the notes. Accordingly, if we default on the notes, we cannot assure you that the trustee would receive enough money from the sale of the collateral to repay you. In addition, we have specified rights to issue additional notes and other parity lien obligations that would be secured by liens on the collateral on an equal and ratable basis with the notes issued in this offering. If the proceeds of any sale of the collateral are not sufficient to repay all amounts due on the notes, then your claims against our remaining assets to repay any amounts still outstanding under the notes would be unsecured.

        The collateral has not been appraised in connection with this offering. Our revolving credit facility permits us to incur additional indebtedness thereunder, and the indenture governing the notes permits us to incur additional obligations secured by liens that have priority over the notes in certain circumstances. The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. The value of the assets pledged as collateral for the notes could be impaired in the future as a result of changing economic conditions, commodity prices, competition or other future trends. Likewise, we cannot assure you that the pledged assets will be saleable or, if saleable, that there will not be substantial delays in their liquidation.

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        In addition, the collateral securing the notes is subject to other liens permitted under the terms of the indenture and the Intercreditor Agreement, whether arising on or after the date the notes are issued. To the extent that third parties hold prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral securing the notes. The indenture does not require that we maintain the current level of collateral or maintain a specific ratio of indebtedness to asset values.

        With respect to some of the collateral, the collateral trustee's security interest and ability to foreclose on the collateral is also limited by the need to meet certain requirements, such as obtaining third party consents, paying court fees that may be based on the principal amount of the parity lien obligations and making additional filings. If we are unable to obtain these consents, pay such fees or make these filings, the security interests may be invalid and the applicable holders and lenders will not be entitled to the collateral or any recovery with respect thereto. We cannot assure you that any such required consents, fee payments or filings can be obtained on a timely basis or at all. These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral. Therefore, the practical value of realizing on the collateral may, without the appropriate consents, fees and filings, be limited.

        In the event of a foreclosure on the collateral under our revolving credit facility (or a distribution in respect thereof in a bankruptcy or insolvency proceeding), the proceeds from the collateral may not be sufficient to satisfy the notes and other parity lien obligations because such proceeds would, under the Intercreditor Agreement, first be applied to satisfy our obligations under our revolving credit facility or other priority lien obligations. Only after all of our obligations under our revolving credit facility and such other obligations have been satisfied will proceeds from the collateral under our revolving credit facility be applied to satisfy our obligations under the notes and other parity lien obligations. In addition, in the event of a foreclosure on the collateral, the proceeds from such foreclosure may not be sufficient to satisfy our obligations under the notes and other parity lien obligations.

        Pursuant to the terms of the indenture governing the notes, we and our restricted subsidiaries may sell assets so long as such sales comply with the asset sales covenant or any other applicable provision of the indenture. Upon any such sale, all or a portion of the interest in any asset sold may no longer constitute collateral. Although we may seek to reinvest proceeds from any asset sales, any assets in which we reinvest may not constitute collateral or be as profitable to us as the assets sold.

        The equity interests in our subsidiaries pledged as part of the collateral to secure the notes may also have limited value at the time of any attempted realization. In particular, in any bankruptcy or similar proceeding, all obligations of the entity whose equity interest has been pledged must be satisfied before any value will be available to the owner of or the creditor secured by such equity interest. If any subsidiary whose equity interest has been pledged as part of the collateral has liabilities that exceed its assets, there may be no remaining value in such subsidiary's equity interest.

The collateral securing the notes and related guarantees may be diluted under certain circumstances.

        The indenture governing our notes and agreements governing our revolving credit facility permit us to incur additional secured indebtedness, including additional notes subject to our compliance with the restrictive covenants in the indenture governing the notes and the agreements governing our revolving credit facility at the time we incur such additional secured indebtedness.

        Any additional notes issued under the indenture governing the notes would be guaranteed by the same guarantors and would have the same security interests, with the same priority, as the notes offered hereby. As a result, the collateral securing the notes would be shared by any additional notes

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we may issue under the applicable indenture, and an issuance of such additional notes would dilute the value of the collateral compared to the aggregate principal amount of notes issued.

The realizable value of our proved reserves may not be sufficient to pay the notes and other future parity obligations in full after repayment of all priority lien obligations.

        Proved reserves constitute a substantial portion of the value of the collateral securing the notes and priority lien obligations. The PV-10 of our proved reserves estimated at December 31, 2014 may significantly exceed the realizable fair market value of such reserves. Our estimated proved reserves as of December 31, 2014 and related PV-10 and Standardized Measure were calculated under SEC rules using twelve-month trailing average benchmark commodity prices, which are substantially above recent WTI spot oil and HH natural gas prices. There is no assurance that oil and natural gas prices will not decline further and our ability to hedge against future commodity price declines may be significantly limited in time and price. Using more recent prices in estimating proved reserves would likely result in a reduction in proved reserve volumes as determined under SEC rules due to economic limits, which would further reduce PV-10 of our proved reserves. In addition, sustained periods with oil and natural gas prices at recent or lower levels and the resultant impact such prices may have on our drilling economics and our ability to raise capital would likely require us to re-evaluate and postpone or eliminate our development drilling, which would likely result in the reduction of some of our proved undeveloped reserves and related PV-10.

        Under the indenture, we could incur a substantial amount of additional priority lien obligations and parity lien obligations. In the event of a default or liquidation, there may not be sufficient realizable value of proved reserves to first repay all priority lien obligations outstanding at such time and then repay the notes and any other outstanding parity obligations.

The provisions of the Intercreditor Agreement relating to the collateral securing the notes limit the rights of holders of the notes with respect to that collateral, even during an event of default.

        Under the Intercreditor Agreement, the parties are generally entitled to receive and apply all proceeds of any collateral to the repayment in full of the obligations under our revolving credit facility before any such proceeds will be available to repay obligations under the notes. In addition, the priority lien collateral agent is generally entitled to sole control of all decisions and actions, including foreclosure, with respect to collateral, even if an event of default under the notes has occurred, and neither the holders of notes nor the collateral trustee is generally entitled to independently exercise remedies with respect to the collateral until specified time periods have elapsed, if at all. In addition, the priority lien collateral agent is entitled, without the consent of holders of notes or the collateral trustee, to amend the terms of the security documents securing the notes and to release the liens of the secured parties on any part of the collateral in certain circumstances. Please read "Description of New Notes—The Intercreditor Agreement." Furthermore, because the holders of priority lien obligations control the disposition of the collateral securing such first-priority obligations and the notes, if there were an event of default under the notes, the holders of the first-priority obligations can decide, for a specified time period, not to proceed against the collateral, regardless of whether or not there is a default under such first-priority obligations. During such time period, unless and until discharge of the first-priority obligations, including our revolving credit facility, has occurred, the sole right of the holders of the notes would be to hold a lien on the collateral.

Security over certain collateral on which a lien in favor of the collateral trustee is required, may not have been perfected on the issue date.

        Security interests over certain collateral, including mortgages on oil and gas properties, which are required under the indenture governing the notes, may not have been perfected on the Issue Date. To the extent such security interests were not perfected on the Issue Date, we would have been required

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to have such security interests thereafter perfected promptly, but in no event later than the date that is 30 days after the Issue Date. In the event that more than a reasonable time passes between the issuance of the notes and the perfection of the security interests on the oil and gas properties, such security interests may be set aside or avoided as a preferential transfer if the owner of the collateral becomes a debtor that is the subject of a voluntary or involuntary bankruptcy case under the U.S. Bankruptcy Code (or under certain similar state law insolvency proceedings) on or before 90 days from the perfection of the security interests. In the event of such a determination in such bankruptcy case or insolvency proceeding, the collateral trustee will not have a perfected security interest in that collateral. Recordation of the mortgages after the issuance date of the notes materially increases the risk that the liens granted by those mortgages could be avoided, in the event of such a bankruptcy.

The collateral will be subject to casualty risks.

        We are obligated under the indenture and collateral arrangements governing the notes to maintain adequate insurance or otherwise insure against hazards as is customarily done by companies having assets of a similar nature in the same or similar localities. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. As a result, it is possible that the insurance proceeds will not compensate us fully for our losses. If there is a total or partial loss of any of the collateral, we cannot assure you that any insurance proceeds received by us or any of the subsidiary guarantors will be sufficient to satisfy all of our obligations, including the notes. We may be required to apply the proceeds from any such loss to repay our obligations under our revolving credit facility.

Rights of holders of notes in the collateral may be adversely affected by bankruptcy proceedings.

        The right of the collateral trustee to repossess and dispose of the collateral upon acceleration is likely to be significantly impaired by federal bankruptcy law if bankruptcy proceedings are commenced in the United States by or against us prior to or possibly even after the collateral trustee has repossessed and disposed of the collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the collateral trustee for the holders of the notes, is prohibited from repossessing its security from a debtor, such as us, in a bankruptcy case, or from disposing of security repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents or profits of the collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given "adequate protection." The meaning of the term "adequate protection" may vary according to circumstances, but it is intended in general to protect the value of the secured creditor's interest in the collateral and may include cash payments or the granting of additional security, if and at such time as the court in its discretion determines, for any diminution in the value of the collateral as a result of the stay of repossession or disposition or any use of the collateral by the debtor during the pendency of the bankruptcy case. In light of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the notes could be delayed following commencement of a bankruptcy case, whether or when the collateral trustee would repossess or dispose of the collateral, and whether or to what extent holders of the notes would be compensated for any delay in payment of loss of value of the collateral through the requirements of "adequate protection." Furthermore, in the event the bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due under the revolving credit facility and on the parity lien obligations, the holders of the notes would have "undersecured claims." Federal bankruptcy laws do not permit the payment or accrual of interest, costs and attorneys' fees for "undersecured claims" during the debtor's bankruptcy case. Additionally, the collateral trustee's ability to foreclose on the collateral on your behalf may be subject to the consent of third parties, prior liens and practical problems associated with the realization of the collateral trustee's security interest in the collateral. The debtor or trustee in a bankruptcy case may seek to void an alleged security interest in collateral for the benefit of the bankruptcy estate, and it

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may be able to successfully do so if the security interest is not properly perfected or was perfected within a specified period of time (generally 90 days) prior to the initiation of such proceeding. If the security interest is avoided, a creditor may hold no security interest and be treated as holding a general unsecured claim in the bankruptcy case. It is impossible to predict what recovery (if any) would be available for such an unsecured claim if we became a debtor in a bankruptcy case. While U.S. bankruptcy law generally invalidates provisions restricting a debtor's ability to assume and/or assign a contract, there are exceptions to this rule which could be applicable in the event that we become subject to a U.S. bankruptcy proceeding.

        In addition, a bankruptcy court may decide to substantively consolidate us and some or all of our subsidiaries in the bankruptcy proceeding. If a bankruptcy court substantively consolidated us and some or all of our subsidiaries, the assets of each entity would become subject to the claims of creditors of all entities. Such a ruling would expose holders of notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, a forced restructuring of the notes could occur through the "cramdown" provisions of the U.S. Bankruptcy Code. Under those provisions, the notes could be restructured over holders' objections as to their interest rate, maturity and other general terms.

Any future pledge of collateral may be avoidable in bankruptcy.

        Any future pledge of collateral in favor of the collateral agent, including pursuant to security documents delivered after the date of the indenture governing the notes, may be avoidable by the pledgor (a debtor in possession) or by its trustee in bankruptcy under U.S. law if certain events or circumstances exist or occur, including, among others, if:

•

the pledgor is insolvent at the time of the pledge;



•

the pledge permits the holder of the notes to receive a greater recovery than if the pledge had not been given; and



•

a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period.

The value of the collateral securing the notes may not be sufficient for a bankruptcy court to grant post-petition interest on the notes in a bankruptcy case of the issuer or any of the guarantors. Should our obligations under the notes, together with our obligations under our revolving credit facility and any other priority lien obligations or parity lien obligations, equal or exceed the fair market value of the collateral securing the notes, the holders of the notes may be deemed to have an unsecured claim for the difference between the fair market value of the collateral, on the one hand, and the aggregate amount of the obligations under our revolving credit facility, any other secured debt and the notes, on the other hand.

        In the event of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding against us or the subsidiary guarantors, holders of the notes will be entitled to post-petition interest under the U.S. Bankruptcy Code only if the value of their security interest in the collateral, taken in order of priority with other obligations secured by the collateral, is greater than the amount of their pre-bankruptcy claim. Holders of the notes may be deemed to have an unsecured claim if our obligations under the notes, together with our obligations under our revolving credit facility, the Third Lien Notes and any other priority lien obligations, parity lien obligations or junior lien obligations, exceed the fair market value of the collateral securing the notes. Holders of the notes that have a security interest in the collateral with a value less than their pre-bankruptcy claim will not be entitled to post-petition interest under the U.S. Bankruptcy Code. The bankruptcy trustee, the debtor-in-possession or competing creditors could possibly assert that the fair market value of the collateral with respect to the notes on the date of the bankruptcy filing (or on the date of confirmation of a chapter 11 plan) was less than the then-current principal amount of the notes. Upon a finding by a

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bankruptcy court that the notes are under-collateralized, the claims in the bankruptcy proceeding with respect to the notes would be bifurcated between a secured claim equal to the value of the interest in the collateral and an unsecured claim, and the unsecured claim would not be entitled to the benefits of security in the collateral. Other consequences of a finding of under-collateralization would be, among other things, a lack of entitlement on the part of holders of the notes to receive post-petition interest, fees or expenses and a lack of entitlement on the part of the unsecured portion of the notes to receive other "adequate protection" under U.S. bankruptcy laws. In addition, if any payments of post-petition interest were made at the time of such a finding of under-collateralization, such payments could be re-characterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to notes. No appraisal of the fair market value of the collateral securing the notes has been prepared in connection with this offering of the notes and, therefore, the value of the collateral trustee's interests in the collateral may not equal or exceed the principal amount of the notes and other secured claims. We cannot assure you that there will be sufficient collateral to satisfy our and the subsidiary guarantors' obligations under the notes.

Rights of holders of notes in the collateral may be adversely affected by the failure to perfect liens on collateral acquired in the future.

        Pursuant to the indenture governing the notes and the collateral documents, subject to certain limited exceptions, our obligations to perfect the liens on the collateral are limited to specified actions. See "Description of New Notes—Provisions of the Indenture Relating to Security."

        The failure to properly perfect liens on collateral could adversely affect the collateral agent's ability to enforce its rights with respect to the collateral for the benefit of the holders of the notes. In addition, applicable law requires that certain property and rights acquired after the grant of a general security interest or lien can be perfected only at or after the time such property and rights are acquired and identified. There can be no assurance that the trustee or the collateral trustee will monitor, or that we, any subsidiary guarantor will inform the trustee or the collateral trustee of, the future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after acquired collateral. The trustee and the collateral trustee for the notes have no obligation to monitor the acquisition of additional property or rights that constitute collateral or the perfection of any security interests therein. Such failure may result in the loss of the practical benefits of the liens thereon or of the priority of the liens securing the notes against third parties.

There are circumstances other than repayment or discharge of the notes under which the collateral will be released.

        Under various circumstances, liens on the collateral securing the notes may be released without your consent, including:

•

a sale, transfer or other disposal of such collateral in a transaction not prohibited under the indenture governing the notes and the delivery of a certificate to the collateral trustee;



•

with respect to the collateral held by a subsidiary guarantor, upon the release of such subsidiary guarantor from its guarantee;



•

to the extent we have defeased or satisfied and discharged the indenture governing the notes;



•

with the consent of the holders of the requisite percentage of notes in accordance with the provisions described under "Description of New Notes—Amendments and Waivers"; and



•

in other circumstances specified in the Intercreditor Agreement, including in connection with the exercise of remedies by the collateral trustee.

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        In addition, a guarantee will be automatically released in connection with a sale of such subsidiary guarantor or a sale of all or substantially all of the assets of that subsidiary guarantor, in each case, in a transaction not prohibited under the indenture governing the notes.

We may not be able to repurchase the notes upon a change of control.

        Upon the occurrence of a change of control (as defined in the indenture governing the notes), unless we exercise our change of control redemption right (as described in "Description of New Notes—Optional Redemption"), we will be required to make an offer to repurchase all outstanding notes at 101% of their principal amount, plus accrued and unpaid interest. The holders of the Third Lien Notes, our outstanding 2020 Senior Notes and 2021 Senior Notes have substantially the same right. We may not be able to repurchase the notes upon a change of control because we may not have sufficient funds and our credit facility may restrict us from making such a repurchase. Accordingly, we may not be able to satisfy our obligations to purchase your notes unless we are able to refinance or obtain waivers under our credit facility or other senior debt, as applicable. Our failure to repurchase the notes upon a change of control would cause a default under the indenture governing the notes and a cross-default under our credit facility. Our credit facility also provides that a change of control, as defined in our credit facility, will be an event of default that permits lenders to accelerate the maturity of borrowings under the agreement and, if that debt is not paid, to enforce security interests in the collateral securing that debt, thereby limiting our ability to raise cash to purchase the notes, and reducing the practical benefit of the offer-to-purchase provisions to the holders of the notes. Accordingly, to avoid the obligation to repurchase the notes, events of default and potential breaches of our credit facility, we may decline business opportunities that could involve a change of control that would otherwise be beneficial to us.

You may not be able to determine when a change of control giving rise to your right to have the notes repurchased by us has occurred following a sale of "substantially all" of our assets.

        A change of control, as defined in the indenture governing the notes, will require us to make an offer to repurchase all notes. The definition of change of control includes a phrase relating to the sale, lease or transfer of "all or substantially all" of our assets. There is no precisely established definition of the phrase "substantially all" under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase their notes as a result of a sale, lease or transfer of less than all of our assets to another individual, group or entity may be uncertain.

Many of the covenants contained in the indenture will be suspended if the notes are rated investment grade by both S&P and Moody's and no default has occurred and is continuing.

        Many of the covenants in the indenture governing the notes will be suspended if the notes are rated investment grade by both S&P and Moody's, provided at such time no default with respect to the notes has occurred and is continuing. There can be no assurance that the notes will ever be rated investment grade, or that if they are rated investment grade, that the notes will maintain such ratings. However, suspension of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force. See "Description of New Notes—Certain Covenants—Covenant Suspension."

Any guarantees by our subsidiaries of the notes could be deemed fraudulent conveyances under certain circumstances, and a court may try to subordinate or void these subsidiary guarantees.

        Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under a guarantee may be subordinated to all other debts of that

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guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee:

•

intended to hinder, delay or defraud any present or future creditor or received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee;



•

was insolvent or rendered insolvent by reason of such incurrence;



•

was engaged in a business or transaction for which the guarantor's remaining assets constituted unreasonably small capital; or



•

intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

        In addition, any payment by that guarantor under a guarantee could be voided and required to be returned to the guarantor or to a fund for the benefit of the creditors of the guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred.

        Generally, however, a subsidiary guarantor would be considered insolvent if:

•

the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;



•

the present saleable value of its assets was less than the amount that would be required to pay its probable liability, including contingent liabilities, on its existing debts as they become absolute and mature; or



•

it could not pay its debts as they became due.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

        The notes are new issues of securities for which there is no established public market. We do not intend to have the notes listed on a national securities exchange or to arrange for quotation on any automated dealer quotation systems. We cannot assure you that an active trading market for the notes will develop or, if developed, that it will continue. In that case, the holders of the notes may not be able to sell their notes at a particular time or at a favorable price. The liquidity of any market for the notes will depend on a number of factors, including:

•

the number of holders of notes;



•

our operating performance and financial condition;



•

the market for similar securities;



•

the interest of securities dealers in making a market in the notes; and



•

prevailing interest rates.

        Even if an active trading market for the notes does develop, there is no guarantee that it will continue. Historically, the market for non-investment grade debt, such as the notes, has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. We cannot assure you that the market, if any, for the notes will be free from similar disruptions or that any such disruptions may not adversely affect the prices at which you may sell your notes.

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We may be unable to repay or repurchase the notes at maturity.

        At maturity, the entire outstanding principal amount of the notes, together with accrued and unpaid interest, will become due and payable. We may not have the funds to fulfill these obligations or the ability to renegotiate these obligations. If upon the maturity date other arrangements prohibit us from repaying the notes, we could try to obtain waivers of such prohibitions from the lenders and holders under those arrangements, or we could attempt to refinance the borrowings that contain the restrictions. In these circumstances, if we were not able to obtain such waivers or refinance these borrowings, we would be unable to repay the notes.

Liquidity concerns could result in a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

        Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit, increase our borrowing costs and potentially require us to post letters of credit for certain obligations.

A downgrade, suspension or withdrawal of the rating assigned by a rating agency to our company or the notes, if any, could cause the liquidity or market value of the notes to decline.

        Credit rating agencies continually revise their ratings for the companies that they follow, including us. The credit rating agencies also evaluate our industry as a whole and may change their credit ratings for us based on their overall view of the industry. In addition, the notes have been rated by Moody's and S&P and may in the future be rated by additional rating agencies. We cannot assure you that any rating assigned will remain for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in that rating agency's judgment, circumstances relating to the basis of the rating, such as adverse changes in our business, so warrant. Any downgrade, suspension or withdrawal of a rating by a rating agency of us or the notes (or any anticipated downgrade, suspension or withdrawal) could reduce the liquidity or market value of the notes. Any future lowering of our ratings or the ratings of the notes may make it more difficult or more expensive for us to obtain additional debt financing. If any credit rating initially assigned to the notes is subsequently lowered or withdrawn for any reason, or there is a negative change to our ratings, you may lose some or all of the value of your investment in the notes.

The market price for the notes may be volatile.

        Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. The market for the notes, if any, may be subject to similar disruptions. Any such disruptions may adversely affect the value of your notes. In addition, subsequent to their initial issuance, the notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar notes, our performance and other factors.

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Risks Related to the Oil and Gas Industry and Our Business

Due to reduced commodity prices and lower operating cash flows, coupled with substantial interest payments, there is doubt about our ability to maintain adequate liquidity through 2015 and our ability to make interest payments in respect of our indebtedness.

        During the past year, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. The substantial reduction in oil and NGL prices has caused a reduction in our forecast of available liquidity and we may not have the ability to maintain our current borrowing base under our reserve based credit facility at its current levels or generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. A sustained material decline in oil, NGL and natural gas prices or a reduction in our oil and natural gas production and reserves would reduce our ability to fund our capital expenditure program and negatively impact our liquidity on an ongoing basis.

Our substantial indebtedness, liquidity issues and potential to seek restructuring transactions may have a material adverse effect on our business and operations.

        Our substantial indebtedness, liquidity issues and potential to seek restructuring transactions may result in uncertainty about our business and cause, among other things:

•

third parties' to lose confidence in our ability to explore and produce oil and natural gas, resulting in a significant decline in our revenues, profitability and cash flow;



•

difficulty retaining, attracting or replacing key employees;



•

employees to be distracted from performance of their duties or more easily attracted to other career opportunities; and



•

our suppliers, vendors, hedge counterparties and service providers to renegotiate the terms of our agreements, terminate their relationship with us or require financial assurances from us.

        These events may have a material adverse effect on our business and operations.

If we are unable to repay or refinance our existing and future debt as it becomes due, we may be unable to continue as a going concern.

        Our existing and future debt agreements could create issues as interest payments become due and the debt matures that will threaten our ability to continue as a going concern. For example, absent any action with respect to the repayment or refinancing of our existing indebtedness or any waivers or amendments to the agreements governing our existing indebtedness, our reserve based revolving credit facility is scheduled to mature in 2018 and our senior notes are scheduled to mature in 2020 and 2021. Additionally, the borrowing base under our reserve based revolving credit facility is subject to at least semi-annual redetermination and as a result, availability thereunder could be reduced and advances in excess of the new availability would need to be repaid. We have substantial interest payments due during the next twelve months. If we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the revolving credit facility, the indentures governing our senior notes, or other agreements governing our indebtedness, an event of default could result, which would permit acceleration of such debt and which could result in an event of default under and acceleration of our other debt and could permit our secured lenders to foreclose on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the

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maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient.

        The consolidated financial statements included in this prospectus have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

A substantial or extended decline in oil and, to a lesser extent, natural gas, prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

        The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. The spot natural gas prices during 2014 ranged from a high of $8.15 to a low of $2.99 per MMBtu and the spot oil prices during 2014 ranged from a high of $107.95 to a low of $53.45 per Bbl. Thus far in 2015, commodity prices have continued to be depressed and volatile. These markets will likely continue to be volatile in the future.

        The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

•

worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;



•

the actions of the Organization of Petroleum Exporting Countries;



•

the price and quantity of imports of foreign oil and natural gas;



•

political conditions in or affecting other oil and natural gas-producing countries;



•

the level of global oil and natural gas exploration and production;



•

the level of global oil and natural gas inventories;



•

localized supply and demand fundamentals and transportation availability;



•

weather conditions and natural disasters;



•

domestic, local and foreign governmental regulations and taxes;



•

speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;



•

price and availability of competitors' supplies of oil and natural gas;



•

technological advances affecting energy consumption; and



•

the price and availability of alternative fuels.

        Substantially all of our production is currently sold to purchasers under short-term (less than 12-month) contracts at market based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. If oil and natural gas prices deteriorate, we anticipate that the borrowing base under our revolving credit facility, which is revised periodically, may be reduced. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could render

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uneconomic a significant portion of our identified drilling locations. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We may not be able to obtain funding under our revolving credit facility because of a decrease in our borrowing base or obtain funding in the capital markets on terms we find acceptable.

        Historically, we have used our cash flows from operations and borrowings under our revolving credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions or to refinance debt obligations. At June 30, 2015, we had no amounts drawn on the credit facility and had outstanding letters of credit obligations totaling $1.5 million. The borrowing base under our revolving credit facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by us or the administrative agent, acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations. Should prices for oil and natural gas remain weak or deteriorate, if we have a downward revision in estimates of our proved reserves, or if we sell oil and natural gas reserves, our borrowing base may be reduced. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility exceeding the borrowing base, we will be required to repay the deficiency within 30 days or in six equal monthly installments thereafter, at our election. We may not have the financial resources in the future to make any mandatory deficiency principal prepayments required under our revolving credit facility, which could result in an event of default.

        In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Since the process for determining the borrowing base under our revolving credit facility involves evaluating the estimated value of some of our oil and natural gas properties using pricing models determined by the lenders at that time, a decline in those prices used, or further downward reductions of our reserves, likely will result in a redetermination of our borrowing base and a decrease in the available borrowing amount at the time of the next scheduled redetermination. In such case, we would be required to repay any indebtedness in excess of the borrowing base.

        Volatility in the public and private capital markets may make it more difficult to obtain funding. There is a risk that the cost of obtaining money from the credit markets may increase in the future as lenders and institutional investors may increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity on terms similar to existing debt or at all, or reduce or cease to provide any new funding. Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

        Our ability to access funds under our revolving credit facility is based on a borrowing base, which is subject to periodic redeterminations based on our proved reserves and commodity prices that will be determined by our lenders using the bank pricing prevailing at such time.

Our level of indebtedness may increase and reduce our financial flexibility.

        As of June 30, 2015, we had $250.9 million available and a borrowing base of $252.4 million under our revolving credit facility, $293.6 million in 2020 Senior Notes, $347.7 million in 2021 Senior Notes,

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$625.0 million in Second Lien Notes and $524.121 million in Third Lien Notes outstanding. In the future, we may incur significant additional indebtedness in order to make future acquisitions or to develop our properties.

        Our current level of indebtedness could affect our operations in several ways, including the following:

•

causing a significant portion of our cash flows to be used to service our indebtedness, thereby reducing the availability of cash flows for working capital, capital expenditures and other general business activities;



•

increasing our vulnerability to general adverse economic and industry conditions;



•

limiting our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;



•

placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, such competitors may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;



•

causing our debt covenants to affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;



•

making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings;



•

impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and



•

making it more difficult for us to satisfy our obligations under the indentures governing our Senior Notes.

        A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control.

        If we are unable to repay our debt out of our cash on hand, we could attempt to refinance such debt, obtain additional borrowings, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that refinancing, additional borrowings, proceeds from the sale of assets or equity financing will be available to pay or refinance such debt. Factors that may affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions, our market value, our reserve levels and our operating performance at the time of such offering or other financing. The inability to repay or refinance our debt could have a material adverse effect on our operations and could result in a reduction in our capital program or lead us to pursue other alternatives to develop our assets.

        In addition, our bank borrowing base is subject to periodic redeterminations on a semi-annual basis, effective October 1 and April 1 and up to one additional time per six-month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrative agent under our revolving credit facility. In the future we could be forced to repay a portion of our then outstanding bank borrowings due to future redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are unable to arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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Our revolving credit facility and the indentures governing our Senior Notes contains certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

        Our revolving credit facility and the indentures governing our Senior Notes includes certain covenants that, among other things, restrict:

•

our ability to incur or assume additional debt or provide guarantees in respect of obligations of other persons;



•

issue redeemable stock and preferred stock;



•

pay dividends or distributions or redeem or repurchase capital stock;



•

prepay, redeem or repurchase certain debt;



•

make loans and investments;



•

create or incur liens;



•

restrict distributions from our subsidiaries;



•

sell assets and capital stock of our subsidiaries;



•

consolidate or merge with or into another entity, or sell all or substantially all of our assets; and



•

enter into new lines of business.

        A breach of the covenants under the indentures governing the Senior Notes or under the revolving credit facility could result in an event of default under the applicable indebtedness. An event of default may allow the creditors to accelerate the related debt and may result in an acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In addition, an event of default under our credit facility would permit the lenders under the facility to terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our revolving credit facility could proceed against the collateral granted to them to secure that debt.

        In addition, our revolving credit facility requires us to maintain certain financial ratios, including a leverage ratio. All of these restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

We may be unable to maintain compliance with certain financial ratio covenants of our outstanding indebtedness which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

        Our revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of June 30, 2015 we are in compliance with our financial covenants; however, we cannot guarantee that we will be able to comply with such terms at all times in the future. Any failure to comply with the conditions and covenants in our revolving credit facility that is not waived by our lenders or otherwise cured could lead to a termination of our revolving credit facility, acceleration of all amounts due under our revolving credit facility, or

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trigger cross-default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our indebtedness impose on us.

Liquidity concerns could result in a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

        Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit, increase our borrowing costs and potentially require us to post letters of credit for certain obligations.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

        Our future financial condition and results of operations will depend on the success of our development, drilling and production activities. Our oil and natural gas drilling and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore or develop drilling locations or properties will depend in part on the evaluation of data obtained through 2D and 3D seismic data, geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The production and operating data that is available with respect to our operating areas based on modern drilling and completion techniques is relatively limited compared to trends where multiple operators have been active for a significant period of time. As a result, we face more uncertainty in evaluating data than operators in more developed trends. For a discussion of the uncertainty involved in these processes, see "—Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these assumptions will materially affect the quantities and present value of our reserves." Our costs of drilling, completing and operating wells are often uncertain before drilling commences. In addition, the application of new techniques in these trends, such as high-graded stimulation designs and horizontal completions, some of which we may not have previously employed, may make it more difficult to accurately estimate these costs. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•

shortages of, or delays in, obtaining equipment and qualified personnel;



•

facility or equipment malfunctions;



•

unexpected operational events;



•

pressure or irregularities in geological formations;



•

adverse weather conditions;



•

reductions in oil and natural gas prices;



•

delays imposed by or resulting from compliance with regulatory requirements;

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•

proximity to and capacity of transportation facilities;



•

title problems; and



•

limitations in the market for oil and natural gas.



•

cost associated with developing and operating oil and gas properties

        In addition, our hydraulic fracturing operations require significant quantities of water. Regions where we operate have recently experienced drought conditions. These conditions could persist in the future, diminishing our access to water for hydraulic fracturing operations. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in delays in operations or increased costs.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves. If the standardized measure of discounted future net cash flows was run at current strip prices, our total estimated proved reserves would be significantly below the standardized measure of discounted future net cash flows at December 31, 2014.

        You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2014, 2013 and 2012, we based the discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

•

actual prices we receive for oil and natural gas;



•

actual cost of development and production expenditures;



•

the amount and timing of actual production; and



•

changes in governmental regulations or taxation.

        The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Prior to our corporate reorganization in April 2012 in connection with our initial public offering, we were not subject to entity level taxation. Accordingly, our standardized measure for periods prior to such reorganization does not provide for federal or state corporate income taxes because taxable income was passed through to our equity holders. However, as a result of our corporate reorganization, we are now treated as a taxable entity for federal income tax purposes and our income taxes are dependent upon our taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this report which could have a material effect on the value of our reserves.

Due to the recent decrease in oil and natural gas prices and if prices continue to decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

        We use the full cost method of accounting for our oil and gas properties. Accordingly, we capitalize and amortize all productive and nonproductive costs directly associated with property acquisition, exploration and development activities. Under the full cost method, the capitalized cost of oil and gas properties, less accumulated amortization and related deferred income taxes may not exceed

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the "cost center ceiling" which is equal to the sum of the present value of estimated future net revenues from proved reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, plus the costs of properties not subject to amortization, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income tax effects. If the net capitalized costs exceed the cost center ceiling, we recognize the excess as an impairment of oil and gas properties. During the six months ended June 30, 2015, we recognized an impairment of $673.1 million, for the amount by which our net capitalized costs exceeded the cost center ceiling. This impairment does not impact cash flows from operating activities but does reduce our earnings and shareholders' equity. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period will not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. We expect to recognize an impairment for the three months ended September 30, 2015, and such impairment is anticipated to be material. We could incur further impairments of oil and natural gas properties in the future, particularly as a result of sustained or further decline in commodity prices.

Oil and natural gas prices are volatile. A substantial portion of our hedges are set to expire in 2015. If we choose not to replace hedges as those contracts expire, our cash flows from operations will be subjected to increased volatility.

        We enter into hedging transactions of our oil and natural gas production revenues to reduce our exposure to fluctuations in the price of oil and natural gas. A substantial portion of our hedges are set to expire in 2015. As our hedges expire, more of our future production will be sold at market prices, exposing us to the fluctuations in the price of oil and natural gas, unless we enter into additional hedging transactions. We may choose not to replace existing hedges as those contracts expire, which will subject our cash flows from operations to increased volatility.

We have incurred losses from operations during certain periods since the beginning of 2008 and may continue to do so in the future.

        We incurred losses from operations of $407.4 million, $15.6 million and $11.8 million for the years ended December 31, 2013, 2010 and 2009, respectively. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically acquire and develop oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these assumptions will materially affect the quantities and present value of our reserves.

        The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these assumptions could materially affect the estimated quantities and present value of reserves shown in this report.

        In order to prepare our estimates, we must estimate production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Estimates of oil and natural gas reserves are

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inherently imprecise. In addition, reserve estimates for properties that do not have a lengthy production history, including the areas in which we operate, are less reliable than estimates for fields with lengthy production histories. There can be no assurance that analysis of previous production data relating to the Mississippian Lime, Anadarko Basin or Upper Gulf Coast Tertiary trend will accurately predict future production, development expenditures or operating expenses from wells drilled and completed using modern techniques. In addition, this data is partially based on vertically drilled wells, which may not accurately reflect production, development expenditures or operating expenses that may result from the application of horizontal drilling techniques.

        Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

        Approximately 52% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2014. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. Accordingly, delays in the development of such reserves, increases in capital expenditures required to develop such reserves and changes in commodity prices could cause us to have to reclassify our proved undeveloped reserves as unproved reserves, which may materially adversely affect our business, results of operations and financial condition.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

        Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.

Drilling locations that we have identified may not yield oil or natural gas in commercially viable quantities.

        We describe some of our drilling locations and our plans to explore those drilling locations in this report. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies

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and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations. In addition, we may not be able to raise the amount of capital that would be necessary to drill a substantial portion of our identified drilling locations.

        Our management team has identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage and acreage currently under option. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques. The results of our horizontal drilling activities are subject to drilling and completion technique risks, and actual drilling results may not meet our expectations for reserves or production. As a result, we may incur material impairment of the carrying value of our unevaluated properties, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

        Risks that we face while horizontally drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our horizontal wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these horizontal drilling and completion techniques can only be evaluated over time as more wells are drilled in the Mississippian Lime, Anadarko Basin and Upper Gulf Coast Tertiary trend and production profiles are established over a sufficiently long time period. If our horizontal drilling results in these trends are less than anticipated, the return on our investment in this area may not be as attractive as we anticipate. The carrying value of our unevaluated properties could become impaired, which would increase our depletion rate per Boe or result in a ceiling test impairment if there were no corresponding additions to recoverable reserves, and the value of our undeveloped acreage in this area could decline in the future.

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Our business depends on the availability of water and the ability to dispose of water. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.

        With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection control wells.

        In addition, concerns have been raised about the potential for earthquakes to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in our operations. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations.

        Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

        We utilize third-party services to maximize the efficiency of our organization. The cost of oilfield services may increase or decrease depending on the demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of frac crews, drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Our business depends on transportation by truck for our oil and condensate production, and our natural gas production depends on transportation facilities that are owned by third parties.

        We transport all of our oil and condensate production by truck, which is more expensive and less efficient than transportation via pipeline. Our natural gas production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

        The disruption of third-party facilities due to maintenance, capacity constraints, or weather could negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due to a lack of cash flows, and if a substantial portion of the production is hedged at lower

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than current market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.

Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production.

        The marketing of oil and gas production depends in large part on the capacity and availability of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If these facilities were unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

        We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

•

environmental hazards, such as unauthorized releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;



•

abnormally pressured formations;



•

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;



•

fires, explosions and ruptures of pipelines;



•

personal injuries and death; and



•

natural disasters.

        Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

•

injury or loss of life;



•

damage to and destruction of property, natural resources and equipment;



•

pollution and other environmental damage;



•

regulatory investigations and penalties;



•

suspension of our operations; and



•

repair and remediation costs.

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        We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

We have received a notice of non-compliance with a continued listing standard from The New York Stock Exchange ("NYSE") for our common stock. If we are unable to avoid the delisting of our common stock from the NYSE, it could have a substantial effect on our liquidity and results of operations.

        On April 1, 2015, we received notification from the NYSE that the price of our common stock had fallen below the NYSE's continued listing standard. Subsequent to April 1, 2015, we regained compliance with the NYSE continued listing requirement; however on July 16, 2015, we received another notification from the NYSE that the price of our common stock had fallen below the NYSE's continued listing standard. Subsequently, we regained compliance with this continued listing standard. The NYSE requires that the average closing price of a listed company's common stock not be less than $1.00 per share for a period of over 30 consecutive trading days.

        Under NYSE rules, a company can avoid delisting if, during the six month period following receipt of the NYSE notice and on the last trading day of any calendar month, a company's common stock price per share and 30 trading-day average share price is at least $1.00. During this six month period, a company's common stock will continue to be traded on the NYSE, subject to compliance with other continued listing requirements. On August 3, the Company announced a 1-for-10 reverse stock split of the Company's common stock to cure the price deficiency, and we subsequently regained compliance within the requisite time period.

        On August 13, 2015, we received another notification from NYSE that our market capitalization and last reported stockholders equity had fallen below the NYSE's continued listing standards. The NYSE requires that a listed company's total market capitalization not be less than $50 million for a period of over 30 consecutive trading days and that our last reported stockholder equity not be less than $50 million. In accordance with NYSE procedures, we have 45 days from our receipt of the notice to submit a business plan to the NYSE demonstrating how we intend to regain compliance with the NYSE's continued listing standards within 18 months. The Listings and Compliance Committee of the NYSE (the "Committee") will then review the business plan for final disposition. In the event the Committee accepts the plan, the Company will be subject to quarterly monitoring for compliance with the business plan and the Company's compliance with other NYSE continued listing requirements. In the event the Committee does not accept the business plan, the Company will be subject to delisting procedures and suspension by the NYSE.

        The NYSE notifications did not affect our business operations or our SEC reporting requirements and did not conflict with or cause an event of default under any of our material debt or other agreements.

        In the future, if our common stock ultimately were to be delisted for any reason, it could negatively impact us by (i) reducing the liquidity and market price of our common stock; (ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to our employees.

Increased costs of capital could adversely affect our business.

        Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to drill our identified

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locations and pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent disruptions and continuing volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We are subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.

        We have previously acquired reserves, properties, prospects and leaseholds from third parties, including the Eagle Property Acquisition and the Anadarko Basin Acquisition. In addition, we will continue to evaluate other acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of assets and other producing properties requires an assessment of several factors, including:

•

recoverable reserves;



•

future oil and natural gas prices and their appropriate differentials;



•

development and operating costs;



•

potential for future drilling and production;



•

validity of the sellers' title to the properties, which may be less than expected at the time of signing the purchase agreement; and



•

potential environmental issues, litigation and other liabilities.

        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the sellers may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

        Significant acquisitions and other strategic transactions may involve other risks, including:

•

diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;



•

the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;



•

difficulty associated with coordinating geographically separate organizations;



•

an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and



•

the challenge of attracting and retaining personnel associated with acquired operations.

        The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our

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business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

        In addition, even if we successfully integrate operations acquired in acquisitions, we may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key personnel, an increase in operating or other costs or other difficulties. We may experience additional challenges integrating the assets of privately operated companies. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may be adversely affected.

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

        We are subject to credit risk due to concentration of our oil, NGL and natural gas receivables with several significant customers. The largest purchaser of our oil, NGLs and natural gas during the year ended December 31, 2014 was Plains Marketing, L.P., accounting for 28%, and for the year ended December 31, 2013 the largest purchaser was ConocoPhillips, accounting for 28% of our total revenues for these periods. Chevron accounted for 41% of our revenues for the year ended December 31, 2012. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition and results of operations.

Our derivative activities could result in financial losses or could reduce our earnings.

        To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, we enter into derivative instruments for a portion of our oil, NGL and natural gas production. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk" and Note 5 to our Audited Consolidated Financial Statements for a summary of our oil commodity derivative positions. We did not designate any of our derivative instruments as hedges for accounting purposes, and we record all derivative instruments in our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

        Derivative instruments expose us to the risk of financial loss in some circumstances, including when:

•

production is less than the volume covered by the derivative instruments;



•

the counter-party to the derivative instrument defaults on its contractual obligations; or



•

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received for basis differentials.

        In addition, our derivative arrangements limit the benefit we would receive from increases in the prices for oil, NGLs and natural gas.

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Large competitors may be attracted to our core operating areas, which may increase our costs.

        Our operations in the Mississippian Lime formation in northwestern Oklahoma, the Anadarko Basin in Texas and Oklahoma and the Upper Gulf Coast tertiary trend in Louisiana may attract companies that have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Their presence in our areas of operations may also restrict our access to, or increase the cost of, oil and natural gas infrastructure, drilling rigs, equipment, supplies, personnel and oilfield services, including fracking equipment and crews. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See "Business—Competition" for additional discussion of the competitive environment in which we operate.

The volatility in commodity prices and business performance may affect our ability to retain key management. The loss of senior management or technical personnel could adversely affect our operations.

        We depend on the services of our senior management and technical personnel. The volatility in commodity prices and business performance may affect our ability to retain key management. The loss of the services of additional members of our senior management or technical personnel could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. Furthermore, if we are unable to find, hire and retain needed key personnel in the future, our business, financial condition and results of operations could be materially and adversely affected.

Title to the properties in which we have an interest may be impaired by title defects.

        We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. The existence of title deficiencies with respect to our oil and natural gas properties could reduce the value or render such properties worthless, which could have a material adverse effect on our business and financial results. A significant portion of our acreage is undeveloped leasehold acreage, which has a greater risk of title defects than developed acreage. Frequently, as a result of title examinations, certain curative work may be required to correct identified title defects, and such curative work entails time and expense. Our inability or failure to cure title defects could render some locations undrillable or cause us to lose our rights to some or all production from some of our oil and natural gas properties, which could have a material adverse effect on our business and financial results if a comparable additional location to drill a development well cannot be identified.

The proposed U.S. federal budget for fiscal year 2015 and proposed legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations and cash flows.

        The Obama administration's budget proposals for fiscal year 2015 contains numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently available to U.S. oil and gas companies. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling and development costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; and increase in the geological and

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geophysical amortization period for independent producers. Should some or all of these provisions become law our taxes could increase, potentially significantly, after net operating losses are exhausted, which would have a negative impact on our net income and cash flows and could reduce our drilling activities. We do not know the ultimate impact these proposed changes may have on our business.

We are subject to various governmental regulations that may cause us to incur substantial costs.

        From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the oil and natural gas industry, changes in these laws and changes in administrative regulations have affected, and in the future could affect, oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect of these adoptions and interpretations may have on our business or financial condition.

        Our business is subject to laws and regulations promulgated by federal, state and local authorities relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government, and third parties and may require us to incur substantial costs of remediation.

Our sales of oil and gas may expose us to extensive regulation.

        The FERC, the Commodity Futures Trading Commission and the Federal Trade Commission hold statutory authority to monitor certain segments of the physical energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales, if any, of oil and gas, we are required to observe the market-related regulations enforced by these agencies.

Our operations are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

        Our oil and natural gas exploration, production and development operations are subject to stringent and complex federal, regional, state and local laws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling, completion and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, and impose substantial liabilities for pollution resulting from our operations. We may be required to make significant capital and operating expenditures to prevent releases, manage wastewater discharges and control air emissions or perform remedial or other corrective actions at our wells and properties to comply with the requirements of these environmental laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations.

        There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of

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historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted.

        Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general in addition to our own results of operations, competitive position or financial condition. For example, in 2012, the EPA published final rules that subject certain oil and natural gas sources, including production operations, to regulation under the NSPS and NESHAP programs that, among other things, require performance of green completions on certain fractured and re-fractured natural gas wells and establish specific requirements regarding emissions from certain production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our expenditures and operating costs, which could adversely impact our business. We may not be able to recover some or any of these costs from insurance.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce.

        Based on the EPA's determination that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth's atmosphere and other climatic changes, the EPA has regulations under existing provisions of the CAA that, among other things, establish pre-construction and operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain permits for their GHG emissions also will be required to meet "best available control technology" standards that typically will be established by the states. In addition, the EPA has adopted regulations requiring the monitoring and annual reporting of GHGs from certain sources in the United States, including, among others, certain onshore and offshore oil and natural gas production facilities.

        In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and a number of states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. For example, in January 2015, the Obama Administration announced plans for the EPA to issue final standards in 2016 that would reduce methane emissions from new and modified oil and natural gas production and natural gas processing and transmission facilities by up to 45 percent from 2012 levels by 2025. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce

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climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, which could adversely affect our production.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas drilling and completion programs. The process is typically regulated by state oil and natural gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final CAA regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015. Compliance with these requirements could increase our costs of development and production, which costs may be significant.

        From time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Moreover, some states, including Louisiana, Texas and Oklahoma, where we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations under certain circumstances. States could elect to prohibit hydraulic fracturing altogether, such as the State of New York announced in December 2014. In addition, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, and experience delays or curtailment in the pursuit of exploration, development, or production activities. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

        In addition, there are also certain governmental reviews underway that focus on environmental aspects of hydraulic fracturing practices. For example, the White House Council on Environmental Quality is coordinating an administration wide review of hydraulic fracturing practices. Also, the EPA is pursuing a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and is expected to issue a draft report for public comment and peer review sometime in the first half of 2015. These existing or any future studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or otherwise.

Studies by both state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens.

        On April 21, 2015, the Oklahoma Geologic Survey ("OGS") issued a document entitled "Statement of Oklahoma Seismicity," in which the agency states "[t]he OGS considers it very likely that

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the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells." This development may result in additional levels of regulation, or increased complexity with respect to existing regulations, that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to inject produced water into disposal wells, and may increase our costs of compliance and doing business.

Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.

        Performance of our operations require that we obtain and maintain numerous environmental and land use permits and other approvals authorizing our regulated activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the affected location or facility. Expansion of our existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all.

The enactment of derivatives legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

        On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

        In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

        The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply or to take steps to qualify for an exemption to such requirements. In addition, the Dodd-Frank Act requires that regulators establish margin rules for uncleared swaps. Although we expect to qualify for the end-user exceptions to the mandatory clearing and margin requirements for swaps entered to hedge our commercial risks, the application of the requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

        The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

        Additionally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity

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instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices.

        The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our financial condition and results of operations.

        In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

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USE OF PROCEEDS

        The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any cash proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are substantially identical to the form and terms of the old notes, except the new notes do not include certain transfer restrictions, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change to our outstanding indebtedness.

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SELECTED FINANCIAL DATA

        The following table sets forth selected financial data of the Company and its consolidated subsidiary over the five-year period ended December 31, 2014, which information has been derived from the Company's audited financial statements. This information should be read in conjunction with, and is qualified in its entirety by, the more detailed information in the Company's financial statements set forth herein.

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Non-GAAP Financial Measures and Reconciliations

        Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

        The Company defines Adjusted EBITDA as earnings before interest income and expense, income taxes, depreciation, depletion and amortization, property impairments, asset retirement obligation accretion, unrealized derivative gains and losses and non-cash share-based compensation expense. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP. The Company believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to its financing methods or capital structure. The Company excludes items such as property and inventory impairments, asset retirement obligation accretion, unrealized derivative gains and losses and non-cash share-based compensation expense, net of amounts capitalized, from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of the Company's operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The Company's computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. The Company believes Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure its ability to meet debt service requirements.

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        The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP measure of net income (loss) and net cash provided by operating activities, respectively.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended December 31, 2014 and the unaudited condensed consolidated financial statements and notes thereto included in this prospectus.

Overview

        We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources. Our operations originally focused on the Upper Gulf Coast Tertiary trend onshore in Louisiana, which we refer to as our "Gulf Coast" operating area. We began operations in the Mississippian Lime trend in Oklahoma and Kansas with the October 1, 2012 closing of our acquisition ("Eagle Property Acquisition") of interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments from Eagle Energy Production, LLC ("Eagle Energy"). On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618.0 million in cash (the "Anadarko Basin Acquisition"), before customary post-closing adjustments. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations and properties in Louisiana, Oklahoma and Texas.

        Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity, constraints, inventory storage levels, basis differentials, and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Recent Developments

Debt Restructuring

        On May 21, 2015, we conducted a debt restructuring transaction which included the issuance of $625.0 million of 10.0% Senior Secured Second Lien Notes due 2020 and the use of the proceeds to repay the outstanding balance of our reserve based revolving credit facility in an amount of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, we exchanged approximately $504.121 million of 12.0% Third Lien Senior Secured Notes due 2020 for approximately $279.8 million of 10.75% Senior Notes due 2020 and $350.3 million of 9.25% Senior Notes due 2021, representing an exchange at 80.0% of the exchanged Senior Unsecured Notes' par value. Additionally, on June 2, 2015, we exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Senior Unsecured Notes' par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and $70.7 million of the principal amount of 2021 Senior Notes were extinguished as a result of the exchanges occurring at a percentage of the Senior Unsecured Notes' par value.

        Additionally, we entered into the Seventh Amendment which provided that upon completion of the offering of the Second Lien Notes and Third Lien Notes, the borrowing base of the credit facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found below under "—Liquidity and Capital Resources."

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Reverse Stock Split

        On August 3, 2015, we completed a 1-for-10 reverse stock split of our outstanding common stock. To effect the reverse stock split, we filed a Certificate of Amendment to our Restated Certificate of Incorporation, which provides for the reverse stock split and for the corresponding reduction in our authorized capital stock to 100 million shares of common stock, $0.01 par value per share, following the reverse stock split. The consolidated financial statements and notes to the consolidated financial statements included in this document give retrospective effect to the reverse stock split for all periods presented.

Dequincy Divestiture

        On April 21, 2015, we closed on the sale of ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44.0 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42.4 million, which is net of customary closing adjustments, was reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale will be used for general corporate purposes. With the Dequincy Divestiture, we no longer have any proved reserves or production in our Gulf Coast operating area.

Risks, Uncertainties and Going Concern

        As a result of substantial declines in oil, natural gas liquids and natural gas prices during the latter half of 2014 and continuing into 2015, the liquidity outlook of the Company has been impacted. Decreases in commodity prices directly impact our revenues and associated operating cash flows and consequently our ability to fund our capital program and service our debt. As a result, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be further impacted as current hedging contracts expire. During the three and six months ended June 30, 2015, we received cash payments on settled derivative contracts of $42.2 million and $94.8 million, respectively. Such cash payments will not be received in 2016 and future periods due to the expiration of our hedging contracts.

        Our interest payment obligations are substantial and the uncertainty associated with our ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about our ability to continue as a going concern. We received a going concern qualification from our independent registered public accounting firm for the year ended December 31, 2014, but obtained a waiver to the credit facility waiving any default as a result of receiving such qualification. The accompanying financial statements do not include any adjustments that might result from the uncertainty associated with our ability to meet obligations as they come due.

        As a result of the commodity price decline and our substantial debt burden, the Company took steps to increase its liquidity and amend certain debt covenants. As discussed above, we completed the Dequincy Divestiture on April 21, 2015, for approximately $42.4 million, net of post-closing adjustments. Additionally, on May 21, 2015, we issued $625.0 million of Second Lien Notes and on May 21, 2015 and June 2, 2015 we exchanged an aggregate of approximately $524.121 million of Third Lien Notes for an aggregate of approximately $306.4 million of 2020 Senior Notes and $352.3 million of 2021 Senior Notes. Approximately $63.9 million of 2020 Senior Notes and $70.7 million of 2021 Senior Notes were extinguished as a result of the exchanges occurring at a percentage of the Senior Unsecured Notes' par value. For additional detail, please see "—Liquidity and Capital Resources" below.

        We also entered into the Seventh Amendment which provided that upon completion of the Second Lien Notes offering and Third Lien Notes exchange, the borrowing base of the credit facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be

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found in Note 10—Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements included in this prospectus. Additionally, further discussion on liquidity can be found below under "—Liquidity and Capital Resources."

Operations Update

Mississippian Lime

        For the three months ended June 30, 2015 and March 31, 2015, our average daily production from the Mississippian Lime area was as follows:

        The following table shows our total number of horizontal wells spud and brought into production in the Mississippian Lime area during the second quarter of 2015:

        In the second quarter of 2015, we invested approximately $67.7 million on completions and drilling new wells.

Anadarko Basin

        For the three months ended June 30, 2015 and March 31, 2015, our average daily production from our Anadarko Basin area was as follows:

        We did not spud any wells in the Anadarko Basin area and did not have any operated drilling rigs in the area during the second quarter of 2015.

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Gulf Coast

        For the three months ended June 30, 2015 and March 31, 2015, our average daily production from the Gulf Coast area was as follows:

        Overall production decreased by 77.6% versus the first quarter of 2015 as a result of the Dequincy Divestiture, which occurred on April 21, 2015. The Dequincy Divestiture represented all of our remaining production and proved reserves in the Gulf Coast region.

        No wells were spud or brought into production in our Gulf Coast area of operation during the second quarter of 2015.

Capital Expenditures

        During the three and six months ended June 30, 2015, we incurred operational capital expenditures of $70.4 million and $163.3 million, respectively, which consisted primarily of:

        Operational capital expenditures were incurred in the following areas:

        We expect to invest between $250.0 million to $275.0 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2015.

Factors that Significantly Affect our Results

        Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in

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the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

        We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we expect to reduce some of the variability in our cash flow from operations. See "—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Exposure" below for discussion of our hedging and hedge positions. We plan to continue our strategy of hedging the risks associated with commodity price volatility; however, given the current low commodity price environment, we may limit the extent of our hedging program in the near-term as appropriate.

        Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost and terms of such capital and operational considerations.

        The volumes of oil and natural gas that we produce are driven by several factors, including:

•

success in the drilling of new wells, including exploratory wells, and the recompletion of existing wells;



•

the amount of capital we invest in the leasing and development of our oil and natural gas properties;



•

facility or equipment availability and unexpected downtime;



•

delays imposed by or resulting from compliance with regulatory requirements; and



•

the rate at which production volumes on our wells naturally decline.

        We follow the full cost method of accounting for our oil and gas properties. In the first quarter and second quarter of 2015, the results of our full cost "ceiling test" required us to recognize an impairment of our oil and gas properties. While these impairments did not impact cash flow from operating activities, they did reduce our earnings and shareholders' equity. We may be required to recognize additional impairments of oil and gas properties in future periods if we experience an extended period of low commodity prices, a downward adjustment to our estimated proved reserves or the present value of estimated future net revenues, or incur actual development costs in excess of those estimates utilized in preparing our reserve reports. Additionally, the expiration of unevaluated acreage leaseholds may increase the probability of future impairments, as the costs associated with the expiring leases would be immediately included in the full cost pool and become subject to the ceiling test limitation without any corresponding increase in reserves or future net revenues.

Results of Operations—Three and Six Months Ended June 30, 2015 Compared to Three and Six Months Ended June 30, 2014

        The following tables summarize our revenue, production and price data for the periods indicated.

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Revenues

Production

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Prices

Three Months Ended June 30, 2015 as Compared to the Three Months Ended June 30, 2014

Oil, natural gas liquids and natural gas sales revenues

        Our oil, NGL and natural gas sales revenues decreased by $85.6 million, or 47.7%, to $93.7 million during the three months ended June 30, 2015, as compared to $179.3 million during the three months ended June 30, 2014. The major contributing factor to this decrease was the substantially lower commodity prices for the three months ended June 30, 2015 as compared to the three months ended June 30, 2014.

        Our oil sales revenues decreased by $63.8 million, or 48.6%, to $67.5 million during the three months ended June 30, 2015, as compared to $131.3 million for the three months ended June 30, 2014. Oil volumes sold decreased 331 Bbls/d, or 2.3%, to 13,959 Bbls/d for the three months ended June 30, 2015, from 14,290 Bbls/d for the three months ended June 30, 2014. The decrease in oil volumes sold was primarily attributable to lower production in our Gulf Coast area due to the Dequincy Divestiture, which impacted sales by 1,494 Bbls/d, as well as lower production from our Anadarko Basin area of 1,443 Bbls/d attributable to a decrease in drilling activity. These decreases were largely offset by increased production in the Mississippian Lime area of 2,606 Bbls/d.

        Our NGL sales revenues decreased by $12.8 million, or 55.5%, to $10.2 million during the three months ended June 30, 2015, as compared to $23.0 million for the three months ended June 30, 2014. NGL volumes sold increased 164 Bbls/day, or 2.5%, to 6,773 Bbls/d for the three months ended June 30, 2015, from 6,609 Bbls/d for the three months ended June 30, 2014. This increase in NGL volumes sold was attributable to the increased production in the Mississippian Lime area of 869 Bbls/d partially offset by a 329 Bbls/d decrease in production from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in our Anadarko Basin area, which resulted in lower NGL production of 376 Bbls/d.

        Our natural gas sales revenues decreased by $9.0 million, or 36.0%, to $16.0 million during the three months ended June 30, 2015, as compared to $25.0 million for the three months ended June 30, 2014. Natural gas volumes sold increased 12,891 Mcf/d or 19.5%, to 78,969 Mcf/day for the three months ended June 30, 2015, from 66,078 Mcf/d for the three months ended June 30, 2014. The increase in natural gas volumes sold was attributable to increased production of 17,138 Mcf/d in the Mississippian Lime area due to the development drilling program and, starting in October 2014, ethane rejection on the gas processing side, partially offset by a decrease in production of 1,367 Mcf/d from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in our Anadarko Basin area, which resulted in lower natural gas production of 2,880 Mcf/d.

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Gains/losses on commodity derivative contracts—net

        Our mark-to-market ("MTM") derivative positions moved from an unrealized loss of $14.3 million for the three months ended June 30, 2014 to an unrealized loss of $61.5 million for the three months ended June 30, 2015. The NYMEX WTI closing price on June 30, 2015 was $59.47 per barrel compared to a closing price of $105.37 per barrel on June 30, 2014.

        Our realized gain on derivatives for the three months ended June 30, 2015 was $42.2 million, compared to a realized loss of $17.1 million for the three months ended June 30, 2014. The following table presents realized gain by type of commodity contract for the three months ended June 30, 2015:

        Cash settlements, as presented in the table above, represent realized gains related to our derivative instruments. In addition to cash settlements, we also recognize fair value changes on our derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

Oil, natural gas liquids and natural gas sales revenues

        Our oil, NGL and natural gas sales revenues decreased by $163.2 million, or 47.1%, to $183.2 million during the six months ended June 30, 2015, as compared to $346.4 million during the six months ended June 30, 2014. The major contributing factor to this decrease was the substantially lower commodity prices for the six months ended June 30, 2015 as compared to the six months ended June 30, 2014.

        Our oil sales revenues decreased by $120.7 million, or 48.8%, to $126.8 million during the six months ended June 30, 2015, as compared to $247.5 million for the six months ended June 30, 2014. Oil volumes sold increased 402 Bbs/d, or 2.9%, to 14,258 Bbls/d for the six months ended June 30, 2015, from 13,856 Bbls/day for the six months ended June 30, 2014. This increase in oil volumes sold was attributable to increased production period over period in the Mississippian Lime area of 3,595 Bbls/d, partially offset by lower production in our Gulf Coast area due to the Dequincy Divestiture, which impacted sales by 1,813 Bbls/d, as well as lower production from our Anadarko Basin area of 1,380 Bbls/d, attributable to a decrease in drilling activity during the period and base production declines.

        Our NGL sales revenues decreased by $27.3 million, or 56.2%, to $21.3 million during the six months ended June 30, 2015, as compared to $48.5 million for the six months ended June 30, 2014. NGL volumes sold increased 564 Bbls/d, or 9.0%, to 6,827 Bbls/d for the six months ended June 30, 2015, from 6,263 Bbls/d for the six months ended June 30, 2014. This increase in NGL volumes was attributable to the increased production in the Mississippian Lime area of 1,367 Bbls/d. Increased production in our Mississippian Lime area was offset by a 388 Bbls/d decrease in production from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in the Anadarko Basin, which contributed to a decrease of 415 Bbls/d.

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        Our natural gas sales revenues decreased by $15.2 million, or 30.2%, to $35.2 million during the six months ended June 30, 2015, as compared to $50.4 million for the six months ended June 30, 2014. Natural gas volumes sold increased 15,572 Mcf/d or 25.1%, to 77,657 Mcf/d for the six months ended June 30, 2015, from 62,085 Mcf/d for the six months ended June 30, 2014. This increase in natural gas volumes sold was attributable to increased production of 19,614 Mcf/day in the Mississippian Lime area, partially offset by a decrease in production of 1,944 Mcf/d from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in the Anadarko Basin, which contributed a decrease of 2,098 Mcf/d.

Gains/losses on commodity derivative contracts—net

        Our MTM derivative positions moved from an unrealized loss of $22.2 million for the six months ended June 30, 2014 to an unrealized loss of $92.7 million for the six months ended June 30, 2015. The NYMEX WTI closing price on June 30, 2015 was $59.47 per barrel compared to a closing price of $105.37 per barrel on June 30, 2014.

        The realized gain on derivatives for the six months ended June 30, 2015 was $94.8 million compared to a realized loss of $32.0 million for the six months ended June 30, 2014. The following table presents realized gain by type of commodity contract for the six months ended June 30, 2015:

        Cash settlements, as presented in the table above, represent realized gains related to our derivative instruments. In addition to cash settlements, we also recognize fair value changes on our derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

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Operating Expenses

        The table below presents a comparison of our expenses on an absolute dollar basis and a per Boe basis. Depending on the relevance, our discussion may reference expenses on an absolute dollar basis, a per Boe basis, or both.

Three Months Ended June 30, 2015 as Compared to the Three Months Ended June 30, 2014

Lease operating and workover expenses

        Lease operating and workover expenses increased $2.0 million, or 10.3%, to $21.8 million for the three months ended June 30, 2015 compared to $19.7 million for the three months ended June 30, 2014. The increase in lease operating and workover expenses was primarily due to workover activity related to production optimization projects, higher environmental compliance costs and higher costs associated with the increase in producing well count period over period, partially offset by lower lease operating expenses due to the Dequincy Divestiture. Lease operating and workover expenses increased to $7.06 per Boe for the three months ended June 30, 2015, an increase of $0.27, or 4.0%, over the $6.79 per Boe for the three months ended June 30, 2014, primarily for the reasons noted above.

Gathering and transportation

        Gathering and transportation expenses were $3.9 million for the three months ended June 30, 2015, as compared to $2.9 million for the three months ended June 30, 2014. These expenses are primarily attributable to a gas transportation, gathering and processing contract covering the Mississippian Lime area that includes a $0.36 per Mmbtu gathering fee based upon wellhead volumes. As such, the increase in our gathering and transportation costs is due to increased natural gas production in our Mississippian Lime area.

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Severance and other taxes

        Severance and other taxes decreased $3.1 million, or 55.5%, to $2.5 million for the three months ended June 30, 2015 compared to $5.6 million for the three months ended June 30, 2014. Severance taxes decreased $3.1 million, or 71.8%, to $1.2 million for the three months ended June 30, 2015, as compared to $4.4 million for the three months ended June 30, 2014. Severance taxes as a percentage of sales changed from 2.4% for the three months ended June 30, 2014 to 1.3% for the corresponding 2015 period due to lower realized pricing as well as a refund received in the 2015 period for production taxes paid in prior periods of $0.6 million. Ad valorem taxes were essentially unchanged for the three months ended June 30, 2015, as compared to the three months ended June 30, 2014.

Depreciation, depletion and amortization (DD&A)

        DD&A expense decreased $15.8 million, or 22.3%, to $55.3 million for the three months ended June 30, 2015 compared to $71.1 million for the three months ended June 30, 2014. The decrease in DD&A expense was driven by downward revisions in our proved undeveloped reserves in the Anadarko Basin from June 30, 2014, which decreased estimated finding and developments costs and as a result, reduced our DD&A expense, as well as the ceiling test impairments recorded during the period. Additionally, our depletion rate has decreased from approximately 2.3% for the three months ended June 30, 2014 to 2.0% for the three months ended June 30, 2015, primarily as a result of increased proved developed reserve volumes. The DD&A rate for 2015 was $17.92 per Boe, compared to $24.47 per Boe for 2014 as a result of the factors discussed above.

Impairment of oil and gas properties

        We recorded pre-tax impairment expense related to our oil and natural gas properties for the three months ended June 30, 2015 of $498.4 million as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of capitalized costs associated with our oil and natural gas properties in our condensed consolidated balance sheets. The impairment expense for the three months ended June 30, 2015 was due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of low commodity prices.

General and administrative (G&A)

        Our G&A expenses decreased by $2.0 million, or 14.7%, to $11.5 million for the three months ended June 30, 2015, compared to $13.5 million for the three months ended June 30, 2014. The decrease is primarily due to lower employee related costs period over period, mainly due to lower headcount and the closure of our Houston office.

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Acquisition and transaction costs

        Our acquisition and transaction costs were $0.3 million for the three months ended June 30, 2015, related to the Dequincy Divestiture, compared to $2.5 million for the three months ended June 30, 2014, representing our expenses related to the Pine Prairie disposition in 2014.

Debt restructuring costs

        During the 2015 period, we engaged various advisors to assist us in analyzing options to improve our financial flexibility and provide additional long-term liquidity. For the three months ended June 30, 2015, we incurred approximately $34.4 million in fees associated with these advisors as well as issuance costs associated with the Second Lien Notes offering and Third Lien Notes exchange.

Other

        Other operating expenses for the three months ended June 30, 2014 were $0.6 million and represent the loss on disposal of field equipment inventory deemed no longer essential to operations. No such expenses were incurred in the three months ended June 30, 2015.

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

Lease operating and workover expenses

        Lease operating and workover expenses increased $5.1 million, or 13.0%, to $45.0 million for the six months ended June 30, 2015 compared to $39.8 million for the six months ended June 30, 2014. The increase in lease operating and workover expenses was primarily due to costs associated with the increase in producing well count period over period and higher environmental compliance costs, partially offset by lower lease operating expenses due to the Dequincy Divestiture. Lease operating and workover expenses increased minimally to $7.31 per Boe for the six months ended June 30, 2015, an increase of $0.08, or 1.1%, from the $7.23 per Boe for the six months ended June 30, 2014, primarily for the reasons noted above.

Gathering and transportation

        Gathering and transportation expenses were $7.4 million for the six months ended June 30, 2015, as compared to $5.8 million for the six months ended June 30, 2014. These expenses are primarily attributable to a gas transportation, gathering and processing contract covering the Mississippian Lime area that includes a $0.36 per Mmbtu gathering fee based upon wellhead volumes. As such, the increase in our gathering and transportation costs is due to increased natural gas production in our Mississippian Lime area.

Severance and other taxes

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        Severance and other taxes decreased $7.2 million, or 54.3%, to $6.1 million for the six months ended June 30, 2015, compared to $13.3 million for the six months ended June 30, 2014. Severance taxes decreased $7.2 million, or 70.4%, to $3.0 million for the six months ended June 30, 2015, as compared to $10.2 million for the six months ended June 30, 2014. Severance taxes as a percentage of sales changed from 2.9% for the six months ended June 30, 2014 to 1.6% for the corresponding 2015 period due to lower realized pricing as well as a refund received in 2015 for production taxes paid in prior periods of $0.6 million. Ad valorem taxes were essentially unchanged for the six months ended June 30, 2015, as compared to the six months ended June 30, 2014.

Depreciation, depletion and amortization

        DD&A expense decreased $24.3 million, or 17.6%, to $113.7 million for the six months ended June 30, 2015 compared to $138.0 million for the six months ended June 30, 2014. The decrease in DD&A expense was driven by downward revisions in our proved undeveloped reserves in the Anadarko Basin from June 30, 2014, which decreased estimated finding and developments costs and as a result, reduced our DD&A expense, as well as the ceiling test impairments recorded during the period. Additionally, our depletion rate has decreased from an average of approximately 2.2% for the six months ended June 30, 2014 to an average of 2.0% for the six months ended June 30, 2015, primarily as a result of increased proved developed reserve volumes. The DD&A rate for 2015 was $18.46 per Boe, compared to $25.02 per Boe for 2014 as a result of the factors discussed above.

Impairment of oil and gas properties

        We recorded pre-tax impairment expense related to our oil and natural gas properties for the six months ended June 30, 2015 and 2014 of $673.1 million and $86.5 million, respectively, as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of capitalized costs associated with our oil and natural gas properties in our condensed consolidated balance sheets. The impairment expense for the six months ended June 30, 2015 was due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of low commodity prices. The impairment expense for six months ended June 30, 2014 was largely due to the transfer of unevaluated property costs to the full cost pool during the first quarter of 2014. During the first quarter of 2014, we transferred $21.4 million and $38.1 million related to the Mississippian Lime and Anadarko Basin areas, respectively, as we released acreage that did not present the best near term development potential.

General and administrative

        Our G&A expenses decreased by $2.0 million, or 8.0%, to $23.1 million for the six months ended June 30, 2015, compared to $25.1 million for the six months ended June 30, 2014. The decrease is primarily attributable to due to lower stock compensation and other employee related expenses due to lower headcount and the closure of the Houston office.

Acquisition and transaction costs

        Our acquisition and transaction costs were $0.3 million for the six months ended June 30, 2014, related to the Dequincy Divestiture, compared to $2.6 million for the six months ended June 30, 2014, representing our expenses related to the Pine Prairie disposition in 2014.

Debt restructuring costs

        During the 2015 period, we engaged various advisors to assist us in analyzing options to improve our financial flexibility and provide additional long-term liquidity. For the six months ended June 30,

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2015, we incurred approximately $36.1 million in fees associated with these advisors as well as issuance costs associated with the Second Lien Notes offering and Third Lien Notes exchange.

Other

        Other operating expenses for the six months ended June 30, 2015 and 2014 were $0.1 million and $0.9 million, respectively. For 2014, these costs represent the loss on disposal of field equipment inventory deemed no longer essential to operations.

Other Income (Expense)

Interest expense

Three Months Ended June 30, 2015 as Compared to the Three Months Ended June 30, 2014

        Interest expense for the three months ended June 30, 2015 and 2014 was $46.0 million and $37.2 million, respectively. The increase in interest expense was primarily due to the issuance of the Second Lien Notes and Third Lien Notes on May 21, 2015. The Second Lien Notes bear interest at 10.0% and were used to repay outstanding borrowings under the credit facility, which had an interest rate of 2.9% at June 30, 2015. Additionally, the Third Lien Notes bear interest at 12.0% and were exchanged for a portion of the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%, respectively. Further, approximately $4.6 million in unamortized debt costs were impaired during the three months ended June 30, 2015 as a result of the Seventh Amendment to the credit facility. For the three months ended June 30, 2015 and 2014, approximately $1.1 million and $3.3 million, respectively, in interest expense was capitalized to oil and gas properties. Capitalized interest was lower due to a decrease in the balance of our unevaluated property from June 30, 2014.

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

        Interest expense for the six months ended June 30, 2015 and 2014 was $83.4 million and $75.7 million, respectively. The increase in interest expense was primarily due to the issuance of the Second Lien Notes and Third Lien Notes on May 21, 2015. The Second Lien Notes bear interest at 10.0% and were used to repay outstanding borrowings under the credit facility, which had an interest rate of 2.9% at June 30, 2015. Additionally, the Third Lien Notes bear interest at 12.0% and were exchanged for a portion of the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%, respectively. Further, approximately $4.6 million in unamortized debt costs were impaired during the six months ended June 30, 2015 as a result of the Seventh Amendment to the credit facility. For the six months ended June 30, 2015 and 2014, approximately $2.1 million and $8.0 million, respectively, in interest expense was capitalized to oil and gas properties. Capitalized interest was lower due to a decrease in the balance of our unevaluated property from June 30, 2014

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Provision for Income Taxes

Three Months Ended June 30, 2015 as Compared to the Three Months Ended June 30, 2014

        We had no income tax benefit or expense for the three months ended June 30, 2015, compared to a benefit of $0.1 million for the three months ended June 30 2014. Our effective tax rate for the second quarter of 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance We expect to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.

        A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its NOLs are realizable except to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

        Our income tax benefit was $9.0 million and $2.3 million for the six months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015, our effective tax rate was a benefit of approximately 1.1%. Our effective tax rate for the six months ended June 30, 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance.

        This year, we recorded $305.9 million in additional valuation allowance in light of the impairment of oil and gas properties and the settlement of certain hedging contracts that existed at December 31, 2014, bringing the total valuation allowance to $309.7 million at June 30, 2015.

Results of Operations—Year Ended December 31, 2014 Compared to Year Ended December 31, 2013 and Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

        The following tables summarize our revenue, production and price data for the periods indicated. Prior to May 1, 2014, our operating results include production, revenue and lease operating expenses attributable to our Pine Prairie field, the sale of which closed effective May 1, 2014. Where applicable, in the following discussion, we have noted normalized production, revenue, lease operating expenses and percentages for prior periods as though the Pine Prairie Disposition occurred as of the beginning of that period.

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Revenues

Production

Prices

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Oil, Natural Gas and Natural Gas Liquids Revenues.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Our oil sales revenues increased by $79.5 million, or 21%, to $466.7 million during the year ended December 31, 2014 as compared to $387.2 million for the year ended December 31, 2013. Oil volumes sold increased 1,240 MBbls or 32% to 5,144 MBbls for the year ended December 31, 2014 from 3,904 MBbls for the year ended December 31, 2013. The increase in oil volumes sold was due to an increase of 1,403 MBbls in production volumes from our Mississippian Lime area attributable to continued increased drilling activity in 2014, and 648 MBbls of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only seven months of results due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in Gulf Coast production of 811 MBbls (of which, approximately 632 MBbls was related to the Pine Prairie area). For the twelve months ended December 31, 2014, we brought approximately 120 wells online, which contributed to the 34% increase in daily production. Average oil sales prices, without realized derivatives, decreased by $8.47 per barrel, or 9%, to $90.71 per barrel for the year ended December 31, 2014 as compared to $99.18 for the year ended December 31, 2013. Of the $466.7 million in total oil sales revenues, $272.9 million was from Mississippian Lime operations, $134.0 million was from the Anadarko Basin and $59.8 million was from the Gulf Coast.

        Our NGLs sales revenues increased by $25.5 million, or 41%, to $87.8 million during the year ended December 31, 2014 as compared to $62.3 million for the year ended December 31, 2013. NGLs volumes sold increased 698 MBbls, or 41%, to 2,417 MBbls for the year ended December 31, 2014 as compared to 1,719 MBbls for the year ended December 31, 2013. The increase in NGLs volumes sold was attributable to an increase of 663 MBbls of production volumes from our Mississippian Lime area and 250 MBbls of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only seven months of results due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in Gulf Coast production of 215 MBbls (of which, approximately 137 MBbls related to the Pine Prairie area). Average NGLs prices, without realized derivatives, increased by $0.05 per barrel, to $36.31 per barrel for the year ended December 31, 2014 as compared to $36.26 per barrel for the year ended December 31, 2013. Of the $87.8 million in total NGLs revenues, $57.7 million was from Mississippian Lime operations, $23.8 million was from the Anadarko Basin and $6.3 million was from the Gulf Coast.

        Our natural gas sales revenues increased by $36.0 million, or 57%, to $99.2 million during the year ended December 31, 2014 as compared to $63.2 million for the year ended December 31, 2013. Natural gas volumes sold increased 6,356 MMcf, or 34%, to 25,013 MMcf for the year ended December 31, 2014 as compared to 18,657 MMcf for the year ended December 31, 2013. The increase in natural gas volumes sold was attributable to an increase of 6,293 MMcf of production volumes from our Mississippian Lime area and 1,960 MMcf of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only seven months of results due to the timing of the Anadarko Basin Acquisition), partially offset by a 1,897 MMcf decrease in production from our Gulf Coast area (of which, approximately 1,577 MMcf related to the Pine Prairie area). Average natural gas prices, without realized derivatives, increased by $0.58 per Mcf, or 17%, to $3.97 per Mcf for the year ended December 31, 2014 as compared to $3.39 per Mcf for the year ended December 31, 2013. Of the $99.2 million in total natural gas sales revenues, $75.4 million was from Mississippian Lime operations, $21.1 million was from Anadarko Basin and $2.7 million was from the Gulf Coast.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Our oil sales revenues increased by $168.8 million, or 77%, to $387.2 million during the year ended December 31, 2013 as compared to $218.4 million for the year ended December 31, 2012. Oil volumes sold increased 1,811 MBbls or 87% to 3,904 MBbls for the year ended December 31, 2013

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from 2,093 MBbls for the year ended December 31, 2012. The increase in oil volumes sold was attributable to an increase of 1,463 MBbls in production volumes from our Mississippian area attributable to a full year of production from the assets (which were acquired on October 1, 2012) and the results from increased drilling activity in 2013, and the addition of 817 MBbls in production volumes from our Anadarko Basin area (which was acquired on May 31, 2013), partially offset by a decrease in Gulf Coast production of 469 MBbls. Production from the Gulf Coast declined due to lower drilling activity during the latter half of 2013 as we focused drilling capital on our newly acquired Anadarko Basin assets. Average oil sales prices, without realized derivatives, decreased by $5.17 per barrel, or 5%, to $99.18 per barrel for the year ended December 31, 2013 as compared to $104.35 for the year ended December 31, 2012, partly due to lower oil prices during 2013 as well as lower oil prices received for our Mississippian Lime and Anadarko Basin production, which is priced off WTI as opposed to LLS for our Gulf Coast production. Of the $387.2 million in total oil sales revenues, $151.7 million was from Gulf Coast operations, $155.9 million was from Mississippian and $79.6 million was from Anadarko Basin.

        Our NGLs sales revenues increased by $38.7 million, or 164%, to $62.3 million during the year ended December 31, 2013 as compared to $23.6 million for the year ended December 31, 2012. NGLs volumes sold increased 1,102 MBbls, or 179%, to 1,719 MBbls for the year ended December 31, 2013 as compared to 617 MBbls for the year ended December 31, 2012. The increase in NGLs volumes sold was attributable to an increase of 789 MBbls of production volumes from our Mississippian Lime area and the addition of 395 MBbls of production volumes from our Anadarko Basin area, partially offset by a decrease in Gulf Coast production of 82 MBbls. Average NGLs prices, without realized derivatives, decreased by $2.01 per barrel, or 5%, to $36.26 per barrel for the year ended December 31, 2013 as compared to $38.27 per barrel for the year ended December 31, 2012. Of the $62.3 million in total NGLs revenues, $13.9 million was from Gulf Coast operations, $34.5 million was from Mississippian Lime and $13.9 million was from Anadarko Basin.

        Our natural gas sales revenues increased by $47.2 million, or 295%, to $63.2 million during the year ended December 31, 2013 as compared to $16.0 million for the year ended December 31, 2012. Natural gas volumes sold increased 12,962 MMcf, or 228%, to 18,657 MMcf for the year ended December 31, 2013 as compared to 5,695 MMcf for the year ended December 31, 2012. The increase in natural gas volumes sold was attributable to an increase of 10,946 MMcf of production volumes from our Mississippian Lime area and the addition of 3,489 MMcf of production volumes from our Anadarko Basin area, partially offset by a 1,473 MMcf decrease in production from our Gulf Coast area. Average natural gas prices, without realized derivatives, increased by $0.58 per Mcf, or 21%, to $3.39 per Mcf for the year ended December 31, 2013 as compared to $2.81 per Mcf for the year ended December 31, 2012. Of the $63.2 million in total natural gas sales revenues, $9.4 million was from Gulf Coast operations, $42.6 million was from Mississippian and $11.2 million was from Anadarko Basin.

Gains/Losses on Commodity Derivative Contracts—Net.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Our MTM derivative positions moved from an unrealized loss of $26.7 million as of December 31, 2013 to an unrealized gain of $157.5 million for the year ending December 31, 2014. The NYMEX WTI closing price on December 31, 2014 was $53.27 per barrel compared to a closing price of $98.42 per barrel on December 31, 2013 and the average oil price of our open derivative contracts was $88.72 per barrel.

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        The realized loss on derivatives for the year ended December 31, 2014 was $18.3 million compared to a realized loss of $17.6 million for the year ended December 31, 2013. See the following table:

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Our MTM derivative positions moved from an unrealized gain of $4.7 million as of December 31, 2012 to an unrealized loss of $26.7 million for the year ending December 31, 2013. We entered into additional derivative contracts during 2013 and the MTM change resulted from higher average hedge volumes and unfavorable derivative contract price variances versus the forward strip price for our production on December 31, 2013. The NYMEX WTI closing price on December 31, 2013 was $98.42 per barrel compared to a closing price of $91.82 per barrel on December 31, 2012.

        The realized loss on derivatives for the year ended December 31, 2013 was $17.6 million compared to a realized loss of $15.8 million for the year ended December 31, 2012. See the following table (in thousands):

Expenses

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Lease Operating and Workover.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Lease operating and workover expenses increased $6.2 million, or 8%, to $79.6 million for the year ended December 31, 2014 compared to $73.4 million for the year ended December 31, 2013. Lease operating expenses increased $9.2 million, or 14%, to $74.5 million for the year ended December 31, 2014 as compared to $65.3 million for the year ended December 31, 2013. This change is almost entirely attributable to the increase in producing well count for the Mississippian Lime and Anadarko Basin areas year over year; there were approximately 150 more active wells in 2014 for these areas versus the prior year. Workover expenses decreased $3.0 million, or 37%, to $5.1 million for the year ended December 31, 2014, as compared to $8.1 million for the year ended December 31, 2013. The Gulf Coast region workover costs decreased approximately $2.2 million period over period. While the total lease operating and workover expenses increased, the per unit amounts decreased to $6.79 per Boe for the year ended December 31, 2014 from $8.41 per Boe for the year ended December 31, 2013, a decrease of 19%, driven primarily by the 34% increase in production year over year.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Lease operating and workover expenses increased $42.9 million, or 141%, to $73.4 million for the year ended December 31, 2013 compared to $30.5 million for the year ended December 31, 2012. Lease operating expenses increased $38.8 million, or 146%, to $65.3 million for the year ended December 31, 2013 as compared to $26.5 million for the year ended December 31, 2012. Lease operating expenses for the year ended December 31, 2013, included a full year of costs related to the assets acquired in the Eagle Property Acquisition (compared to only three months for the year ended December 31, 2012) and seven months of costs related to the assets acquired in the Anadarko Basin Acquisition which closed on May 31, 2013. Of this increase, $31.3 million relates to the increase in producing well count in all areas, which increased approximately 150% year over year due to the Anadarko Basin Acquisition and increased drilling activity in the Mississippian Lime area. The remaining $7.5 million is attributable to surface maintenance and other costs. During 2013, we continued to make investments in our operating areas to reduce lease operating costs, specifically in salt water disposal infrastructure in our Gulf Coast region and in our electrical infrastructure and salt water disposal infrastructure in the Mississippian Lime. Workover expenses increased $4.1 million, or 103%, to $8.1 million for the year ended December 31, 2013, as compared to $4.0 million for the year ended December 31, 2012. Of this increase, approximately $2.9 million relates to the Mississippian Lime area workover costs and $1.3 million relates to the Anadarko area workover costs partially offset by a decrease of $0.1 million in Gulf Coast workover costs. Lease operating and workover expenses increased to $8.41 per Boe for the year ended December 31, 2013 from $8.34 per Boe for the year ended December 31, 2012, an increase of 1%, which was primarily attributable to the factors noted above.

Gathering and Transportation.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Gathering and transportation expenses increased $7.9 million, or 144%, to $13.4 million for the year ended December 31, 2014 compared to $5.5 million for the year ended December 31, 2013. These expenses are primarily attributable to an amended gas transportation, gathering and processing contract which commenced during the third quarter of 2013 in the Mississippian Lime and included a $0.36 per MMBtu gathering fee based upon wellhead volumes. As such, the year ended December 31, 2013 includes only two quarters of the expense. No gathering and transportation expenses were incurred in 2012.

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Severance and Other Taxes.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Severance and other taxes decreased $2.9 million, or 11% to $24.3 million for the year ended December 31, 2014 as compared to $27.2 million for the year ended December 31, 2013. Severance taxes decreased $3.6 million, or 17%, to $17.7 million for the year ended December 31, 2014 compared to $21.3 million for the year ended December 31, 2013 and as a percentage of sales, changed from 4.2% for the year ended December 31, 2013 to 2.7% for the corresponding 2014 period due to lower effective severance tax rates in our Mississippian Lime and Anadarko Basin areas and lower production period-over-period in the relatively higher tax Gulf Coast region resulting from reduced drilling activity in 2014 and the Pine Prairie Disposition. Ad valorem taxes increased $0.7 million, or 12%, to $6.6 million for the year ended December 31, 2014, as compared to $5.9 million for the year ended December 31, 2013, related to increased ad valorem taxes in the Anadarko Basin and Gulf Coast area.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Severance and other taxes increased $2.3 million, or 9%, to $27.2 million for the year ended December 31, 2013 as compared to $24.9 million for the year ended December 31, 2012. Severance taxes decreased by $0.8 million, or 4%, and accounted for $21.3 million of the 2013 amount. This decrease was primarily attributable to the geographic production mix, with lower oil, NGL and natural gas sales revenue from the Gulf Coast area, and to higher oil, NGLs and natural gas sales revenue from the Mississippian and Anadarko Basin, where severance tax rates are lower than in the Gulf Coast. Severance taxes for the year ended December 31, 2013 and 2012 were 4.2% and 8.6%, respectively, as a percentage of oil, NGL and natural gas sales revenue.

        Ad valorem taxes increased $3.1 million, or 111%, to $5.9 million for the year ended December 31, 2013 as compared to $2.8 million for the year ended December 31, 2012. This change directly correlates to the increase in active well count, which increased approximately 150% year over year due to the Anadarko Basin Acquisition and development drilling in 2013 across all areas.

Depreciation, Depletion and Amortization (DD&A).

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        DD&A expense increased $19.5 million, or 8%, to $269.9 million for the year ended December 31, 2014 compared to $250.4 million for the year ended December 31, 2013. The DD&A rate for the year ended December 31, 2014 was $23.01 per Boe compared to $28.67 per Boe for the year ended December 31, 2013. The increase in total DD&A expense for the year ended December 31, 2014 was primarily due to higher oil, NGLs and natural gas production attributable to a full year of production from the Anadarko Basin Acquisition assets as well as developmental drilling during 2014 in the Mississippian Lime area. The lower DD&A rate per Boe is attributable to the overall growth in proved reserves during 2014.

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Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        DD&A expense increased $124.8 million, or 99%, to $250.4 million for the year ended December 31, 2013 compared to $125.6 million for the year ended December 31, 2012. The DD&A rate for the year ended December 31, 2013 was $28.67 per Boe compared to $34.32 per Boe for the year ended December 31, 2012. The increase in total DD&A expense for the year ended December 31, 2013 was primarily due to higher oil, NGLs and natural gas production attributable to a full year of production from the Mississippian Lime assets acquired in October 2012, the addition of production from the Anadarko Basin Acquisition and developmental drilling during 2013. The lower DD&A rate per Boe is attributable to the addition of reserves with the Anadarko Basin Acquisition, as well as overall growth in proved reserves during 2013.

Impairment of Oil and Gas Properties.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Our impairment of oil and gas properties pursuant to the full cost "ceiling test" was $83.5 million, net of taxes, for the year ended December 31, 2014 compared to $319.6 million, net of taxes, for the year ended December 31, 2013. The most significant factors affecting the 2014 impairment, which was recorded in the first quarter of 2014, related to the transfer of unevaluated property costs to the full cost pool. While we did not record a ceiling test impairment during the fourth quarter of 2014 (as SEC case pricing was still favorable at average prices of $94.99/Bbl for oil and $4.35/MMBtu for natural gas), we would have recorded an additional before tax impairment ranging from $600 million to $800 million at December 31, 2014 if we had used current forward strip pricing from February 2015 in the calculation of the present value of future net revenues from oil and gas properties in determining the full cost ceiling limitation. Should commodity prices remain at their current levels, we will be required to recognize future impairments in the carrying value of oil and gas properties and such impairments may be material.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Our impairment of oil and gas properties pursuant to the full cost "ceiling test" was $319.6 million, net of taxes, for the year ended December 31, 2013. There was no impairment for the year ended December 31, 2012.

        The most significant factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool during 2013 and negative reserve revisions in our Gulf Coast area. During 2013, we transferred $61.2 million of Gulf Coast unevaluated property costs to the full cost pool based upon our lack of future plans for further evaluation or development of those leases, and $168.4 million of Mississippian unevaluated property costs attributable to leases that expired during 2013 or that we currently intend to allow to expire in 2014. The negative reserve revisions in our Gulf Coast area were mainly attributable to variability in well performance, our decision during the second quarter to halt further development in our West Gordon field and unfavorable cost revisions.

General and Administrative (G&A).

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Our G&A expenses decreased to $48.7 million for the year ended December 31, 2014 from $53.3 million for the year ended December 31, 2013. The $4.6 million decrease period over period is primarily related to: $2.0 million in additional COPAS recoveries, $11.5 million less in transition services payments (in 2013 and part of 2014, payments were made as a result of the Eagle Property Acquisition and Anadarko Basin Acquisition) and $3.4 million less in other taxes, partially offset by an

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increase of $10.1 million in employee costs (including salary, bonus, severance related to the Houston office closure and share-based compensation) and $2.2 million of other G&A costs.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Our G&A expenses increased to $53.3 million for the year ended December 31, 2013 from $30.5 million for the year ended December 31, 2012. The increase in G&A expenses of $22.8 million, or 75%, was primarily due to salary, benefits, and other expenses of $10.7 million related to the increase in headcount, which increased from 93 full-time employees at December 31, 2012 to 217 full-time employees at December 31, 2013; an increase in payments made under the Eagle Transition Services Agreement of $0.6 million; payments made under the Panther Transition Services Agreement of $10.2 million; and other costs of $1.3 million.

Acquisition and Transaction Costs.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Our acquisition and transaction costs decreased by $7.7 million to $4.1 million for the year ended December 31, 2014 from $11.8 million for the year ended December 31, 2013. For the 2014 period, these costs generally represent our expenses related to the Pine Prairie Disposition discussed above. For the 2013 period, these costs represent our expenses related to the Anadarko Basin Acquisition discussed above.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Our acquisition and transaction costs decreased by $3.1 million for the year ended December 31, 2013 from $14.9 million for the year ended December 31, 2012. These total costs of $11.8 million incurred in 2013 represent our expenses through December 31, 2013 related to the Anadarko Basin Acquisition and are primarily attributable to due diligence, legal and other advisory fees that are required to be expensed under US GAAP.

Other.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Other operating expenses for the year ended December 31, 2014 were $5.1 million, compared to $0.6 million for the year ended December 31, 2013. These expenses represent the loss on disposal of, or market value adjustments to, field equipment inventory deemed no longer useful to current operations, penalty fees associated with the early termination of a drilling contract, as well as other miscellaneous expenses.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Other operating expenses for the year ended December 31, 2013 were $0.6 million, compared to no related costs for the year ended December 31, 2012. These costs represent the loss on disposal of, or market value adjustments to, field equipment inventory deemed no longer useful to current operations.

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Other Income (Expense)

Interest Expense

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Interest expenses, before capitalized interest, for the years ended December 31, 2014 and 2013 was $150.0 million and $115.4 million, respectively. The increase in interest expense was primarily due to a full year of interest associated with the 2021 Senior Notes (as discussed below) issued in 2013. Our average outstanding balance under our revolving credit facility was $386.7 million during the year ended December 31, 2014, compared to $252.7 million the year ended December 31, 2013, and related to $12.7 million of the total interest expense of $150.0 million for the year ended December 31, 2014. Of the remainder, $64.9 million was interest incurred under the 2021 Senior Notes, $64.5 million was interest incurred under the 2020 Senior Notes and $7.9 million represented amortization of deferred financing costs. Of the total interest expense, $12.4 million and $32.2 million was capitalized to oil and gas properties, resulting in $137.6 million and $83.1 million in interest expense, net of capitalized interest, for the years ended December 31, 2014 and 2013, respectively.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Interest expense (before capitalized interest) for the years ended December 31, 2013 and 2012 was $115.4 million and $24.2 million, respectively. The increase in 2013 interest expense was primarily due to the issuance during 2013 of the 2021 Senior Notes (as discussed below) and a full year of interest expense associated with the 2020 Senior Notes (as discussed below) issued during 2012, in addition to a higher average outstanding balance under our revolving credit facility during the 2013 period. Our average outstanding balance under our revolving credit facility was $252.7 million during the 2013 period, versus $160.0 million for the 2012 period, and related to $7.1 million of the total interest expense of $115.4 million. The remainder of the interest expense for the year ended December 31, 2013, $108.3 million, related to interest expense of $37.8 million on the 2021 Senior Notes, $64.5 million on the 2020 Senior Notes, and amortization of deferred financing costs of $6.0 million. Of total interest expense, $32.2 million and $11.2 million was capitalized, resulting in $83.1 million and $13.0 million in net interest expense for years ended December 31, 2013 and 2012, respectively.

Provision for Income Taxes.

Year Ended December 31, 2014 as Compared to the Year Ended December 31, 2013

        Income tax expense was $6.4 million for the year ended December 31, 2014. This represents an application of our estimated effective tax rate (including state income taxes) for the year ended December 31, 2014 of 5.2% to the income incurred throughout the year. The significant reasons for the change from an income tax benefit to an expense during the year ended December 31, 2014 was $157.5 million of net unrealized gains on commodity derivative contracts which resulted in pre-tax book income of $123.3 million.

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        The effective tax rate of 5.2% for the year ended December 31, 2014 includes the impact of a $39.9 million reduction in the valuation allowance originally established against our federal tax net operating losses ("NOL") attributable to the unrealized hedging gains during 2014 as discussed above.

Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012

        Income tax benefit was $146.5 million for the year ended December 31, 2013. This represents an application of our estimated effective tax rate (including state income taxes) for the year ended December 31, 2013 of 29.9% to the loss incurred throughout the year. The significant reasons for the change from an income tax expense to a benefit during the year ended December 31, 2013 were the absence of a change in tax status charge during 2013 (as this event took place in 2012), and the occurrence of a book loss for the year ended December 31, 2013.

        In light of the impairment of oil and gas properties, we have recorded a $45.7 million valuation allowance against our federal and State of Louisiana tax NOLs, as we do not believe that it is more-likely-than-not that this portion of our NOLs are realizable. We believe that the balance of the NOLs are realizable only to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

Liquidity and Capital Resources

        Our financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. The content below and under "Risks, Uncertainties, and Going Concern" above addresses important factors affecting our financial condition, liquidity and capital resources and debt covenant compliance.

        At June 30, 2015, our liquidity consisted of approximately $250.9 million of available borrowing capacity under our credit facility and $151.0 million of cash and cash equivalents.

        Expenditures for exploration and development of oil and natural gas properties and payments for interest related to our outstanding debt are the primary use of our capital resources and liquidity. We expect to invest a total of between $250.0 million and $275.0 million of capital for exploration, development and lease and seismic acquisition during the year ending December 31, 2015. Additionally, we expect to capitalize between $4.0 million and $6.0 million of interest expense during that same period.

        In April 2015, we closed a purchase and sale agreement covering the sale of our remaining producing assets in Louisiana for total consideration of approximately $42.4 million cash, net of customary closing adjustments. The net proceeds will be used for general corporate purposes.

        On May 21, 2015, we issued $625.0 million of Second Lien Notes and utilized the proceeds to repay the outstanding balance of the credit facility in an amount of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, we exchanged approximately $504.121 million of Third Lien Notes for approximately $279.8 million of 2020 Senior Notes and $350.3 million of 2021 Senior Notes, representing an exchange at 80.0% of the exchanged Senior Unsecured Notes' par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Senior Unsecured Notes' par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and $70.7 million of the principal amount of 2021 Senior Notes were extinguished as a result of the exchanges occurring at a percentage of the Senior Unsecured Notes' par value.

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        Additionally, we and Midstates Sub also entered into the Seventh Amendment which provided that upon completion of the offering of the Second Lien Notes and Third Lien Notes exchange, the borrowing base of the credit facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility.

        Our interest payment obligations are substantial. The table below summarizes the cash interest payments on our various debt facilities as of June 30, 2015 (in thousands):

        Our future success in growing proved reserves and production and meeting our interest obligations will be highly dependent on our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our credit facility or by securing other external sources of funding. Though we have no current plans to do so, we may from time to time seek to retire, purchase or exchange our outstanding debt in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Significant Sources of Capital

Reserve-based Credit Facility

        We maintain a $750.0 million credit facility with a borrowing base of $252.4 million supported by our Mississippian Lime and Anadarko Basin oil and gas assets. At June 30, 2015, we had no amounts drawn on the credit facility and had outstanding letters of credit obligations totaling $1.5 million.

        The credit facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of our oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon the Company's borrowing base utilization, between 2.00% and 3.00% per annum. At June 30, 2015 and 2014, the weighted average interest rate was 2.9% and 2.8%, respectively.

        In addition to interest expense, the credit facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.500% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

        The borrowing base under the credit facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by us or the administrative agent, acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations.

        Under the terms of the credit facility, we are required to repay any amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base or grant liens on additional property having sufficient value to eliminate such excess. We are permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent's notice regarding such borrowing base reduction.

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        On March 24, 2015, we and Midstates Sub entered into a Sixth Amendment (the "Sixth Amendment") to the credit facility. The Sixth Amendment amended the required ratio of net consolidated indebtedness to EBITDA under the Credit Agreement for each of the fiscal quarters in 2015 from 4.0:1.0 to 4.5:1.0. Additionally, the Sixth Amendment amended the mortgage requirements under the credit facility to provide for an increase from 80% to 90% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

        On May 21, 2015, we and Midstates Sub entered into a Seventh Amendment (the "Seventh Amendment") to the credit facility. The Seventh Amendment provided that, with the completion of the offering of the Second Lien Notes and Third Lien Notes exchange (both discussed below), our borrowing base would be reduced to approximately $252.4 million. The Seventh Amendment also eliminated the required ratio of net consolidated indebtedness to EBITDA covenant and added a ratio of Total Senior Indebtedness (as defined therein) to EBITDA of not more than 1.0:1.0. The next scheduled redetermination of the borrowing base is October 2015.

        On August 5, 2015, we and Midstates Sub entered into an Eighth Amendment (the "Eighth Amendment") to the credit facility. The Eighth Amendment increases the limitation on certain leases and lease agreements into which Midstates and Midstates Sub may enter into in any period of twelve consecutive calendar months during the life of such leases from $2,000,000 to $3,500,000.

2020 Senior Notes

        On October 1, 2012, we issued $600 million in aggregate principal amount of 2020 Senior Notes conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the "Securities Act"). In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2020 Senior Notes rank pari passu in right of payment with the 2021 Senior Notes, the Second Lien Notes and Third Lien Notes. The 2020 Senior Notes were co-issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. We do not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries. The indenture governing the 2020 Senior Notes (the "2020 Senior Notes Indenture") does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub. On May 21, 2015 and June 2, 2015, a total of approximately $306.4 million of 2020 Senior Notes were exchanged for Third Lien Notes, as discussed above.

        At any time prior to October 1, 2015, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020 Senior Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, we may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the 2020 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to the redemption date. On or after October 1, 2016, we may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2020 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2020 Senior Notes redeemed, up to the redemption date.

        Upon the occurrence of certain change of control events, as defined in the 2020 Senior Notes Indenture, each holder of the 2020 Senior Notes will have the right to require that we repurchase all or a portion of such holder's 2020 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

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2021 Senior Notes

        On May 31, 2013, we issued $700.0 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes, Second Lien Notes and Third Lien Notes. The 2021 Senior Notes were co-issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. The indenture governing the 2021 Senior Notes (the "2021 Senior Notes Indenture") does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans us or limit our ability to advance loans to Midstates Sub. On May 21, 2015 and June 2, 2015, a total of approximately $352.3 million of 2021 Senior Notes were exchanged for Third Lien Notes, as discussed above.

        Prior to June 1, 2016, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes (less the amount of 2021 Senior Notes redeemed pursuant to the preceding paragraph) with the net proceeds of any equity offerings at a redemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, we may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the 2021 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to, the redemption date. On or after October 1, 2016, we may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2021 Senior Notes redeemed, up to, the redemption date.

        Upon the occurrence of certain change of control events, as defined in the 2021 Senior Notes Indenture, each holder of the 2021 Senior Notes will have the right to require that we repurchase all or a portion of such holder's 2021 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

Second Lien Notes

        On May 21, 2015, we and Midstates Sub issued and sold $625.0 million aggregate principal amount of Second Lien Notes in a private placement conducted pursuant to Rule 144A under the Securities Act. The Second Lien Notes mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company's credit facility (including any extension or refinancing of such facility). The Second Lien Notes have an interest rate of 10.0% and interest is payable semi-annually on June 1 and December 1 of each fiscal year. The Second Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of our future restricted subsidiaries (the "Guarantors") and will be initially secured by second-priority liens on substantially all of our and the Guarantors' assets that secure our credit facility.

        On May 21, 2015, in connection with the offering of Second Lien Notes, we and Midstates Sub entered into a registration rights agreement with the initial purchasers of the Second Lien Notes pursuant to which the Issuers are obligated, within 270 days after the issuance of the Second Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Second Lien Notes for substantially identical registered new notes. We will be obligated to pay liquidated damages consisting of additional interest on the Second Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

        The Second Lien Notes are our senior secured obligations and rank effectively junior to its obligations under the credit facility, effectively senior to its existing and future unsecured indebtedness,

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effectively senior to our Third Lien Notes and all future junior lien obligations, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Second Lien Notes, pari passu with all of our existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior to any existing or future subordinated debt.

        Upon the occurrence of certain change of control events, as defined in the indenture governing the Second Lien Notes, each holder of the Second Lien Notes will have the right to require that we repurchase all or a portion of such holder's 2020 Second Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

Third Lien Notes

        On May 21, 2015 and June 2, 2015, we issued approximately $504.121 million and $20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement and in exchange for an aggregate of $306.4 million of the 2020 Senior Notes and $352.3 million of the 2021 Senior Notes. The Third Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Guarantors. The Third Lien Notes are initially secured by third-priority liens on substantially all of the Company's assets that secure the credit facility. The Third Lien Notes have an interest rate of 12.0%, consisting of cash interest of 10.0% and paid-in-kind interest of 2.0%, per annum and mature on the earlier of June 1, 2020 or 12 months after the maturity date of our credit facility (including any extension or refinancing of such facility). Interest is payable semi-annually on June 1 and December 1 of each fiscal year.

        On May 21, 2015, in connection with the issuance of the Third Lien Notes, we entered into a registration rights agreement with the initial purchasers of the Third Lien Notes pursuant to which we are obligated, within 270 days after the issuance of the Third Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Third Lien Notes for substantially identical registered new notes. We will be obligated to pay liquidated damages consisting of additional interest on the Third Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

        The Third Lien Notes are senior secured obligations of the Company and rank effectively junior to its obligations under the credit facility and Second Lien Notes to the extent of the value of the collateral securing such indebtedness, effectively senior to its existing and future unsecured indebtedness to the extent of the value of the collateral securing the Third Lien Notes, effectively senior to all future junior lien obligations that rank below a third-priority basis to the extent of the value of the collateral securing the Third Lien Notes, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Third Lien Notes, equal in right of payment to all of the Company's existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior in right of payment to any existing or future subordinated debt.

        Upon the occurrence of certain change of control events, as defined in the indenture governing the Third Lien Notes, each holder of the Third Lien Notes will have the right to require that we repurchase all or a portion of such holder's Third Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

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Debt Covenants

        The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes contain covenants that, among other things, restrict our ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with our affiliates; (vii) consolidate, merge or sell substantially all of our assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business we conduct and (x) enter into agreements restricting the ability of our current and any future subsidiaries to pay dividends.

        Additionally, the credit facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of Total Senior Indebtedness to EBITDA (as defined therein) of not more than 1.0:1.0 and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The credit facility also limits our ability to make any dividends, distributions or redemptions.

Cash Flows from Operating, Investing and Financing Activities—Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

        The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods presented. For information regarding the individual components of our cash flow amounts, please refer to the Unaudited Condensed Consolidated Statements of Cash Flows included in this prospectus.

        Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "—Quantitative and Qualitative Disclosures About Market Risk."

        The following information highlights the significant period-to-period variances in our cash flow amounts (table in thousands):

Cash flows provided by operating activities

        Net cash provided by operating activities decreased by $34.9 million to $138.7 million for the six months ended June 30, 2015 as compared to $173.6 million for the six months ended June 30, 2014. The decrease in net cash provided by operating activities was primarily the result of a decrease in our oil and gas revenues of $163.2 million due to lower commodity pricing, offset partially by increased settlements of derivatives of $126.8 million.

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Cash flows used in investing activities

        Net cash used in investing activities was $150.0 million and $128.0 million during the six months ended June 30, 2015 and 2014, respectively. The increase in net cash used in investing activities was primarily the result of a decrease in proceeds from the sale of oil and gas properties of $105.0 million offset by a decrease in capital expenditures of $85.3 million. During the 2014 period, the Company completed the Pine Prairie disposition for approximately in $147.5 million in proceeds as compared to the Dequincy Divestiture that occurred during the 2015 period for approximately $40.3 million in proceeds. The decrease in our capital expenditures is a result of lower rig count during the 2015 period due to low commodity pricing.

Cash flows provided by (used in) financing activities

        Net cash provided by financing activities was $150.8 million for the six months ended June 30, 2015, as compared to cash used in financing activities of $49.0 million for the six months ended June 30, 2014. The increase in net cash provided by financing activities was primarily the result of the issuance of the Second Lien Notes of $625.0 million and additional borrowings from the credit facility of $33.0 million offset partially by the repayment of the credit facility of $468.2 million and debt restructuring costs of $36.1 million during the 2015 period as compared to borrowings from the credit facility of $84.0 million and repayments of the credit facility of $131.0 million during the 2014 period.

Cash Flows from Operating, Investing and Financing Activities—Year Ended December 31, 2014 Compared to Year Ended December 31, 2013 and Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

        The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods presented. For information regarding the individual components of our cash flow amounts, please refer to the Audited Consolidated Statements of Cash Flows included in this prospectus.

        The following information highlights the significant period-to-period variances in our cash flow amounts (table in thousands):

Cash flows provided by operating activities

        Net cash provided by operating activities was $351.5 million, $237.6 million and $145.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. The increase in net cash provided by operating activities for the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily the result of an increase in oil and natural gas revenues attributable to higher production and favorable working capital changes, partially offset by lower realized commodity prices. The increase in net cash provided by operating activities for the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily driven by an increase in production in all commodities and an increase in natural gas prices, partially offset by a decrease in oil and NGL prices.

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Cash flows used in investing activities

        We had net cash used in investing activities of $404.3 million, $1.2 billion and $781.4 million during the years ended December 31, 2014, 2013 and 2012, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. During the year ended December 31, 2014, $561.7 million was spent on our drilling program, partially offset by $147.7 million in proceeds received for the Pine Prairie Disposition, $3.0 million in proceeds received related to the Exploration Agreement with PetroQuest and $1.4 million in other asset sales. During the year ended December 31, 2013, $573.7 million was spent on our drilling program and $620.1 million for the Anadarko Basin Acquisition. The increase in net cash used in investing activities during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to the Anadarko Basin Acquisition and continued expansion of our drilling programs.

Cash flows provided by financing activities

        Net cash provided by financing activities was $31.1 million, $981.0 million and $647.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. For the year ended December 31, 2014, we had draws on the revolver of $165.0 million and repayments (using a portion of the proceeds from the Pine Prairie Disposition) of $131.0 million. For the year ended December 31, 2013, cash sourced through financing activities was provided primarily from net long-term borrowings of $1.0 billion, consisting of the 2021 Senior Notes of $700 million and borrowings under the revolver of $341.5 million, offset by repayments of our revolving credit facility of $34.3 million. For the year ended December 31, 2012, cash sourced through financing activities was provided primarily from proceeds from our initial public offering of $213.6 million and net long-term borrowings of $459.2 million, consisting of the 2020 Senior Notes of $600 million and advances from our revolving credit facility, offset by repayments of our revolving credit facility during the year. Our long-term debt was $1.7 billion, $1.7 billion and $694.0 million at December 31, 2014, 2013 and 2012, respectively.

Critical Accounting Policies and Estimates

        We prepare our financial statements and the accompanying notes in conformity with GAAP, which requires our management to make estimates and assumptions about future events that affect the reported amounts in our financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Our management routinely discusses the development, selection and disclosure of each of the critical accounting policies.

        When used in the preparation of our financial statements, estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our condensed consolidated financial position, results of operations and cash flows. Following is a discussion of our most critical accounting policies:

        Reserves Estimates.    Proved oil and gas reserves are the estimated quantities of natural gas, crude oil and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing operating conditions and government regulations. Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where

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reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

        Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a "ceiling" limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

        Reserves as of December 31, 2014, 2013 and 2012 were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month, held flat for the life of the production, except where prices are defined by contractual arrangements.

        We have elected not to disclose probable and possible reserves or reserve estimates in this filing.

        Revenue Recognition.    Our revenue recognition policy is significant because revenue is a key component of the results of operations and of the forward-looking statements contained in the analysis of liquidity and capital resources. We record revenue in the month our production is delivered to the purchaser, but payment is generally received 30 to 90 days after the date of production. At the end of each month, we estimate the amount of production that was delivered to the purchaser and the price that will be received. We use our knowledge of our properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other factors as the basis for these estimates. We record the variances between our estimates and the actual amounts received in the month payment is received.

        Share-Based Compensation.    We account for share-based compensation awards in accordance with FASB ASC 718, Compensation—Stock Compensation. We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense in "General and administrative expense" in our consolidated statements of operations.

        Financial Instruments.    Our financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivatives. Commodity derivatives are recorded at fair value. The carrying amount of our other financial instruments approximate fair value because of the short-term nature of the items or variable pricing.

        Derivative financial instruments are recorded in our consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative's fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recorded within revenues in "Gains (losses) on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operating activities.

        Asset Retirement Obligations.    We have obligations to remove tangible equipment and facilities associated with our oil and natural gas wells, and to restore land at the end of oil and natural gas production operations. The removal and restoration obligations are associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

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        Recent Accounting Pronouncements.    We reviewed recently issued accounting pronouncements that became effective during the year ended December 31, 2014, and determined that none would have a material impact on our condensed consolidated financial statements, with the exception of ASU 2014-09, "Revenue from Contracts with Customers" and ASU 2014-15, "Presentation of Financial Statements—Going Concern," (both effective for annual reporting periods beginning after December 15, 2016), which we are still evaluating.

        Off-Balance Sheet Arrangements.    Currently, we do not have any off-balance sheet arrangements as defined under Item 303(a)(4) (ii) of Regulation S-K.

Quantitative and Qualitative Disclosures About Market Risk

        We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

        The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in Note 4—Risk Management and Derivative Instruments in the Notes to the Unaudited Condensed Consolidated Financial Statements included in this prospectus.

        Commodity Price Exposure.    We are exposed to market risk as the prices of oil and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged in the past and expect to hedge a significant portion of our future production. However, given the current low commodity price environment, we may limit the extent of our hedging program in the near-term as appropriate.

        We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of June 30, 2015, we utilized fixed price swaps to reduce the volatility of oil and natural gas prices on a portion of our future expected oil and natural gas production.

        For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

        The following is a summary of our commodity derivative contracts as of June 30, 2015:

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        At June 30, 2015 and December 31, 2014, all of our commodity derivative contracts were with seven bank counterparties. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

        Interest Rate Risk.    At June 30, 2015, we had no indebtedness outstanding under our credit facility, $293.6 million outstanding in 2020 Senior Notes, which bear interest at 10.75%, $347.7 million outstanding in 2021 Senior Notes, which bear interest at 9.25%, $625.0 million outstanding in Second Lien Notes, which bear interest at 10.0% and $525.3 million in Third Lien Notes, which bear interest at 12.0%. At June 30, 2015 and 2014, the weighted average interest rate was 2.9% and 2.8%, respectively, for the credit facility.

        A 1.0% increase in each of the average LIBOR and federal funds rate for the three and six months ended June 30, 2014 would have resulted in an estimated $1.0 million and $1.9 million, respectively, increase in interest expense, of which a portion may be capitalized. There were no borrowings on the credit facility as of June 30, 2015.

        At June 30, 2015, we do not have any interest rate derivatives in place. In the future, we may utilize interest rate derivatives to mitigate our exposure to change in interest rates. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        During the second quarter of 2015, our management carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. As a result of the material weakness described below, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at a reasonable level of assurance as of June 30, 2015. Notwithstanding such material weakness, management concluded that the financial statements and other financial information included in this report present fairly, in all material respects, the financial condition, results of operations and cash flows for all periods presented.

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Material Weakness in Internal Control over Financial Reporting and Remediation Efforts

        During the second quarter of 2015, we identified a material weakness in our internal control over financial reporting related to the review of our Consolidated Statements of Cash Flows. This material weakness resulted from errors in our restated amounts within our Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012, which were reported in Item 5. Other Information, of our First Quarter 2015 Quarterly Report.

        Although we continue to believe that these errors are immaterial, we have revised the restated amounts for the years ended December 31, 2013 and 2012 in Item 5. Other Information, of our Second Quarter 2015 Quarterly Report. There continues to be no impact to the Consolidated Balance Sheets as of December 31, 2014 and 2013, or the Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012. If not remediated, this material weakness could result in a material misstatement of the Consolidated Statements of Cash Flows.

Changes in Internal Control over Financial Reporting

        Except for the remediation efforts described below, there were no changes in our internal control over financial reporting during the quarter ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

        Upon identification of the errors in Item 5. Other Information, of our First Quarter 2015 Quarterly Report, we began remediation efforts to improve our internal controls. We have implemented additional review procedures targeted to ensuring the completeness and accuracy of our Consolidated Statements of Cash Flows. Our remediation efforts are still in progress. The implementation of these changes to our control environment is ongoing, and our remediation efforts have not yet been subject to management's testing.

Other Items

Contractual Obligations

        The following table summarizes our contractual obligations as of June 30, 2015 (in thousands):

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Recent Accounting Pronouncements

        On May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"). ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period, considering the one year deferral approved by the FASB on July 9, 2015. The standard permits the use of either the retrospective or cumulative effect transition method. Early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

        In April 2015, the FASB issued Accounting Standards Update 2015-03, "Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835)". The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard should be applied retrospectively and is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of this guidance will have a material impact on its financial position, results of operations or cash flows.

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BUSINESS

        Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Sub, which was previously a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.'s initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates Sub became a wholly-owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. Our common stock, par value $0.01 per share, has been listed on the NYSE since April 2012.

        On May 31, 2013, we closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash, before customary post-closing adjustments. We funded the purchase price with a portion of the net proceeds from the private placement of $700 million in aggregate principal amount of the 2021 Senior Notes, which also closed on May 31, 2013.

        On May 1, 2014, we closed on the sale of all of its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, before customary post-closing adjustments. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres, and did not include our acreage and production in the western part of Louisiana in Beauregard and Calcasieu Parish or other undeveloped acreage held outside the Pine Prairie field.

        We have oil and gas operations and properties in Oklahoma, Texas and Louisiana. At June 30, 2015, we operated oil and natural gas properties as one reportable segment engaged in the exploration, development and production of oil, natural gas liquids ("NGLs") and natural gas. Our management evaluated performance based on one reportable segment as there were not significantly different economic or operational environments within its oil and natural gas properties.

        The following table summarizes, by areas of operation, our estimated proved reserves as of December 31, 2014, their corresponding pre-tax PV-10 values and our fourth quarter 2014 average daily production rates:

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        During 2014, we incurred the following operational and total capital expenditures (in thousands):

        As noted above, we incurred operational capital expenditures of $530.4 million during the year ended December 31, 2014, of which $383.2 million was spent in the Mississippian Lime, $139.8 million was spent in the Anadarko Basin and $7.4 million was spent in the Gulf Coast area. We expect to invest between $250 million and $275 million of capital for exploration, development and lease and seismic acquisition in 2015. Additionally, we expect to capitalize between $4 million and $6 million of interest expense. Furthermore, we incurred operational capital expenditures of $163.3 million during the six months ended June 30, 2015, of which $156.6 million was spent in the Mississippian Lime, $4.7 million was spent in the Anadarko Basin and $2.1 million was spent in the Gulf Coast area.

Strategies

        Our goal is to grow our reserves, production and cash flows at an attractive rate of return on invested capital. To achieve these objectives, we strive to:

•

Operate in a safe and environmentally responsible manner;



•

Allocate capital to projects that generate the highest returns;



•

Maintain a sustainable, diverse inventory of low-cost, high-margin resource plays;



•

Drill in the highest potential areas of the resource plays in which we operate;

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•

Build contiguous acreage positions that drive operating efficiencies;



•

Be the operator of our assets, whenever possible;



•

Be the low-cost driller and producer in each area where we operate;



•

Utilize derivative contracts to mitigate the impact of oil, NGL or natural gas price volatility, while locking in acceptable cash flows required to support future capital expenditures; and



•

Attract and retain the best people.

        Development of our multi-year drilling inventory.    We intend to drill and develop our current acreage position to maximize the value of our primarily oil and liquids rich resource potential from resource plays in our core areas of operation where we can capitalize on our operating expertise. For 2015, we plan to allocate substantially all of our drilling and completions capital budget to development activities in the Mississippian area, based on the relatively stronger economic returns expected from these assets in the current commodity price and cost environment.

•

Mississippian.  Our Mississippian assets acquired on October 1, 2012 are located in Oklahoma and target the Mississippian Lime and Hunton formations. The Mississippian Lime is an expansive carbonate hydrocarbon system located in the Anadarko Basin, primarily in northern Oklahoma. We currently intend to continue development of these liquids rich properties using horizontal wells and multi-stage frac technology. The Hunton formation is a limestone formation that produces primarily natural gas from our acreage in Lincoln County, Oklahoma. Because the Hunton targets primarily natural gas, our capital deployment will be focused on the Mississippian Lime until natural gas prices demonstrate sustained improvement from recent levels. At December 31, 2014, we had approximately 99,100 gross (79,000 net) acres under lease in the area, comprised of approximately 78,100 gross (66,300 net) leased acres in the Mississippian Lime and approximately 21,000 gross (12,700 net) acres in the Hunton. As of June 30, 2015, we had four drilling rigs in operation. We expect to spud between 58 to 64 gross (46 to 52 net) horizontal wells, including non-operated wells, during 2015 on this acreage.



•

Anadarko Basin.  Our Anadarko Basin assets acquired on May 31, 2013 are located in Western Oklahoma and Texas and target multiple objectives in the Pennsylvanian section. We target the Cleveland, Marmaton, Cottage Grove and Tonkawa formations in the Anadarko Basin by utilizing horizontal wells and multi-stage frac technology. At December 31, 2014, we had approximately 161,500 gross (122,600 net) acres under lease in the Anadarko Basin, comprised of approximately 44,100 gross (32,300 net) leased acres in Oklahoma and approximately 117,400 gross (90,300 net) acres in the Texas. As of June 30, 2015, we did not have any drilling rigs in operation in this area. In the current price environment, we do not expect to spud any wells on this acreage during 2015. We intend to continue to evaluate this prospective acreage for future drilling plans if commodity prices continue to decline and/or drilling and completion costs experience sustained improvement.



•

Gulf Coast.  At December 31, 2014 we had approximately 68,200 gross (50,600 net) acres under lease and/or lease option. On March 5, 2014, we executed a Purchase and Sale Agreement ("PSA") to sell all of our ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres and closed on May 1, 2014. On June 25, 2014, we entered into an exploration agreement with PetroQuest Energy ("PetroQuest") to sell 50% of our ownership interest in the Fleetwood prospect area in Louisiana. During 2015, we plan to participate with PetroQuest and other owners in the joint exploration and development of the Fleetwood area in Iberville, Point Coupee, and West Baton Rouge Parish, Louisiana. We executed a PSA in March 2015 for the sale of our Dequincy assets, our only remaining producing properties in Louisiana, for total consideration of $44 million (subject to customary

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purchase price adjustments). The PSA includes our ownership interest in developed and undeveloped acreage totaling approximately 12,700 net mineral acres in the Dequincy area. During the fourth quarter 2014, the properties produced approximately 1,300 Boe per day. The transaction does not include our acreage and interests in the Fleetwood area of Louisiana. The net proceeds from the sale will be used to pay down a portion of the outstanding borrowings under our revolving credit facility and for general corporate purposes. The transaction had an effective date of March 1, 2015 and closed on April 21, 2015, subject to customary closing conditions. In the last year, we have shifted capital from the Gulf Coast area and as of June 30, 2015 we did not have any operated rigs active in the area. Our intent is to continue high grading inventory in Louisiana for future capital deployment. Other than the Fleetwood project, we expect limited development activity in the Gulf Coast area in 2015 as we continue focusing on the development of our Mississippian assets.

        Maintain operatorship across a diverse asset base.    Our diverse set of assets and high degree of operating control, facilitated by our position as operator on the majority of our properties, provide flexibility with respect to drilling and completion techniques and the timing and amount of capital expenditures that support growth and help us meet our targeted financial profile.

        Utilize our technical and operating expertise to enhance returns.    Our technical teams are focused on the application of modern reservoir evaluation and drilling and completion techniques to reduce risk and enhance returns in our core areas. We utilize 2D, 3D and micro seismic data, existing sub-surface well control data, detailed reservoir characterization and geologic and geochemical modeling to identify areas with significant exploration and development potential. These areas become targets for our leasing activity. Once we have identified a potential target, we attempt to maximize returns by applying modern drilling and completion techniques that maximize recoveries in a cost efficient and economically attractive manner. We utilize reservoir evaluation methods such as conventional and rotary sidewall coring, pressure sampling and other reservoir description techniques to better understand the ultimate potential of a particular area. We believe future development across our acreage position can be further optimized with specialized completion techniques, infill drilling, horizontal wellbore optimization and enhanced recovery methods.

        Selectively increase our acreage position.    While we believe our existing acreage positions provide significant growth opportunities, we continue to strategically increase our leasehold position in what we believe are the most prospective areas of our acreage. We believe our current Oklahoma and Texas acreage is highly prospective in the Pennsylvanian and Mississippian Lime sections and may be prospective in both shallower and deeper geologic sections.

        Apply rigorous investment analysis to capital allocation decisions.    We employ rigorous investment analysis to determine the allocation of capital across our many drilling opportunities and in evaluating potential acquisitions. We are focused on maximizing the internal rate of return on our investment capital and screen drilling opportunities and acquisition opportunities by measuring risk and financial return, among other factors. We continually evaluate our inventory of potential investments by these measures, incorporating past drilling results, historical knowledge and new information we have gathered.

        Extensive technical knowledge in our areas of operations.    In our Mississippian Lime area, we believe our team's early experience operating in this trend gives us a competitive advantage with respect to geological understanding, drilling and completion techniques and infrastructure development. In the Anadarko Basin area, that we have a history of drilling horizontally in several of the Pennsylvanian sands since 2005. We have had operations in the Upper Gulf Coast Tertiary trend since 1993. We believe our extensive operating experience in the trend provides us with an expansive technical understanding and ability to optimize production from these properties. We believe we have developed amicable and mutually beneficial relationships with acreage owners in all of our core

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operating areas, which we believe also provides us with a competitive advantage with respect to our leasing and development activity. We also benefit from long-term relationships with local service companies and infrastructure providers that we believe contribute to our efficient low-cost operations.

Summary of Oil and Gas Properties and Operations

Mississippian Lime

        At December 31, 2014, our Mississippian Lime assets consisted of approximately 66,300 net prospective acres in the Mississippian Lime trend, with 64,100 net acres in Woods and Alfalfa Counties of Oklahoma, which we currently believe is the core of the trend. We currently intend to develop these liquids-rich properties using horizontal wells. We also own approximately 12,700 net acres in Lincoln County, Oklahoma, which produces from, and is prospective in, the Hunton formation.

        Our properties in this area represented 90% of our total proved reserves as of December 31, 2014. As of December 31, 2014, we held an average working interest and average net revenue interest of 69% and 55%, respectively, in this area.

        For the years ended December 31, 2014 and 2013, our average daily production from this area was as follows:

        During 2014, we invested approximately $383.2 million and spud 76 net horizontal wells in this region. Of the 16 net wells spud during the last quarter of 2014, three were drilling, 10 were awaiting completion and three were producing at year-end.

        Our main operating area in the Mississippian Lime is defined by de-risked acreage primarily in Woods County, where we are engaged in development drilling. Our current development drilling is targeting the Mississippian Lime interval, where we anticipate ultimate development of at least four horizontal wells per 640 acre section. We are also testing different drilling and completion techniques to determine the most cost effective design in this area.

        In 2015, we plan to invest approximately $250 million to $275 million in the spudding of between 58 to 64 gross wells, including non-operated wells. Our plans are to continue to actively develop this area while evaluating exploration potential beyond our current position.

Expansion Areas within Mississippian Lime

        The majority of our rigs currently operating in the Mississippian Lime are focused on infill drilling in our core area; during 2015, we plan to drill four to six wells to extend our de-risked acreage to the west and hold acreage.

Anadarko Basin

        Our Anadarko Basin assets were acquired on May 31, 2013, and at December 31, 2014, consisted of approximately 122,600 net acres in the Anadarko Basin, with 90,300 net acres in Texas and 32,300 net acres in western Oklahoma. We took over operation of the properties on December 1, 2013. As of December 31, 2014, we did not have any drilling rigs in operation in this area.

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        Our properties in this area represented 8% of our total proved reserves as of December 31, 2014. As of December 31, 2014, we held an average working interest and average net revenue interest of 66% and 52%, respectively, in this area.

        For the years ended December 31, 2014 and 2013, our average daily production from this area was as follows:

        During 2014, we invested approximately $139.8 million and spud 26 net horizontal wells in the area. Of the three net wells spud during the last quarter of 2014, two were awaiting completion and one was producing at year-end. Since year-end, three wells have been completed and brought online.

        In the current commodity price and drilling and completion cost environment, we do not currently plan to spud any wells on this acreage during 2015, however we will continue to evaluate for opportunities. For 2015, our efforts will focus on reducing well maintenance costs and production downtime and these efforts alone will not be sufficient to arrest the natural decline in production that occurs as we deplete our developed reserves. Additionally, because of our limited capital resources, we may allow leasehold rights on acreage not held by production to expire, which could reduce our future drilling opportunities in this area.

Gulf Coast

        In the Gulf Coast, our current acreage positions and evaluation efforts are concentrated in Louisiana in the Wilcox interval of the Upper Gulf Coast Tertiary trend and is characterized by well-defined geology, including tight sands featuring multiple productive zones typically located within large geologic traps. As of December 31, 2014, we had, including acreage in the Fleetwood area, approximately 50,600 net acres in the trend under lease and/or lease option.

        We closed on the sale of producing properties and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana on May 1, 2014 for estimated net proceeds of $147.5 million in cash, after post-closing adjustments. The sale has an effective date of November 1, 2013. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres, and did not include our acreage and production in the western part of Louisiana in Beauregard Parish or other undeveloped acreage held outside the Pine Prairie field. Production from the assets included in this sale averaged 626 and 3,453 Boe/d during the years ended December 31, 2014 and 2013, respectively, and 2,366 Boe/d during the quarter ended December 31, 2013. There was no production from Pine Prairie during the quarter ended December 31, 2014. Our remaining Gulf Coast areas of operation are concentrated in the South Bearhead and North Coward's Gully fields.

        On June 25, 2014, we entered into an exploration agreement with PetroQuest to sell 50% of our ownership interest in the Fleetwood prospect area in Louisiana. We plan to participate with PetroQuest and other owners in the joint exploration and development of the Fleetwood area in Iberville, Point

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Coupee, and West Baton Rouge Parish, Louisiana. There are currently three wells planned to be spud in the first six months of the year; we will have a carried working interest ranging from 25% to 50% in those wells. The carried working interest is capped at a total credit of $14 million.

        In March 2015, we executed a PSA for the sale of our Dequincy assets, our only remaining producing properties in Louisiana, for total consideration of $44 million (subject to customary purchase price adjustments). The PSA includes our ownership interest in developed and undeveloped acreage totaling approximately 12,700 net mineral acres in the Dequincy area. During the fourth quarter 2014, the properties produced approximately 1,300 Boe per day. The transaction does not include our acreage and interests in the Fleetwood area of Louisiana. The net proceeds from the sale will be used to pay down a portion of the outstanding borrowings under our revolving credit facility and for general corporate purposes. The transaction has an effective date of March 1, 2015 and closed on April 21, 2015.

        Our properties in this area represented 2% of our total proved reserves as of December 31, 2014. As of December 31, 2014, we held an average working interest and average net revenue interest of 96% and 75%; respectively, in this area.

        For the years ended December 31, 2014 and 2013, our average daily production from this area was as follows:

        In the last year, we have shifted capital to the Mississippian Lime assets and as of December 31, 2014 did not have any rigs in operation in the Gulf Coast. Our intent is to continue high grading inventory in Louisiana for future capital deployment. Other than the Fleetwood area, we expect limited activity as we continue focusing on our Mississippian assets. We currently have no drilling rigs operating in this area as we have devoted our capital to developing our Mississippian Lime assets; however, we plan to continue to evaluate our acreage as well as other potential exploration opportunities in the Gulf Coast area. Because of our limited activity in this area, our production will continue to decline as we deplete our developed reserves.

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Estimated Proved Reserves

        Our proved reserves have grown from 75.5 to 127.8 MMBoe from year end 2012 to year end 2013 and from 127.8 to 153.7 MMBoe from year end 2013 to year end 2014. Our reserve growth in these periods is due directly to the extensions and discoveries associated with our drilling activities in each year and, during 2012, the Eagle Property Acquisition and during 2013, the Anadarko Basin Acquisition. As a result, we have increased our average daily production at a compound annual growth rate of 79% from 995 Boe/d in the year ended December 31, 2008 to 32,137 Boe/d in the year ended December 31, 2014.

        Our proved developed reserves have increased 24.9 MMBoe from 48.7 MMBoe (or 38% of total reserves) to 73.6 (or 48% of total reserves) as a result of our drilling activities. Our proved undeveloped reserves have grown from 79.0 MMBoe to 80.1 MMBoe from December 31, 2013 to December 31, 2014. During this time, we spent $237 million of our capital expenditures on drilling proved undeveloped locations and converted 14.9 MMBoe from proved undeveloped reserves to proved developed reserves. In addition, we added 77.0 MMBoe of proved undeveloped reserves through extensions and discoveries and had net negative revisions of 22.9 MMBoe related to proved undeveloped reserves, of which 3.1 MMBoe related to reductions at our Gulf Coast area and

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22.1 MMBoe related to reductions in our Anadarko Basin area, offset by 2.3 MMBoe in positive revisions in the Mississippian Lime area. These net negative revisions in the Gulf Coast were primarily due to our lack of future development plans in this area. The net negative revisions in the Anadarko Basin were primarily due to our current drilling plans which did not allow for development of these proved undeveloped reserves within five years of their initial booking.

        In addition, 16.4 MMBoe of reserves were sold as a result of the Pine Prairie Disposition, which closed on May 1, 2014.

        All of our proved undeveloped reserves as of December 31, 2014 are expected to be developed within five years of their initial booking.

Independent petroleum engineers

Mississippian Lime, Anadarko, and Gulf Coast Area Reserves

        For our Mississippian Lime and Anadarko area, our estimated reserves and related future net revenues at December 31, 2014 are based on reports prepared by Cawley, Gillespie & Associates, Inc. ("CGA"), in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period established by the SEC. For our Anadarko area, our estimated reserves and related future net revenues at December 31, 2013 are based on reports prepared by Cawley, Gillespie & Associates, Inc. ("CGA"), in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period established by the SEC.

        The reserves estimates shown herein have been independently evaluated by CGA, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the reserves report incorporated herein was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 27 years of practical experience in petroleum engineering, with over 25 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

        Our estimated reserves and related future net revenues for the Mississippian Lime area at December 31, 2013 and 2012 were based on reports prepared by NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period established by the SEC.

        Our estimated reserves and related future net revenues at December 31, 2014 for the Gulf Coast area are based on reports prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period established by the SEC. Our estimated reserves and related future net revenues for the Gulf Coast area at December 31, 2013 and 2012 were based on reports prepared by NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period established by the SEC.

        The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial

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organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. Philip R. Hodgson. Mr. Barg, a Licensed Professional Engineer in the State of Texas (No. 71656), has been practicing consulting petroleum engineering at NSAI since 1989 and has over 6 years of prior industry experience. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Technology used to establish proved reserves

        Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI and CGA employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.

Internal controls over reserves estimation process

        We maintain an internal staff of petroleum engineers, land and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to NSAI and CGA in their reserves estimation process. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from the Company's accounting records, which are subject to external quarterly reviews, annual audits and their own set of internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. The Company's current ownership

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in mineral interests and well production data are incorporated into the reserve database as well and verified to ensure their accuracy and completeness. At December 31, 2014, Mick Matejka, our Director—Corporate Reserves, was the technical person primarily responsible for overseeing the preparation of our reserve estimates and reported directly to the CEO. Mr. Matejka has over 15 years of experience in the estimation and evaluation of oil and gas assets. Mr. Matejka started his career with Royal Dutch Shell working as a reservoir engineer for various asset teams in the Gulf of Mexico and the Lower 48, and eventually as exploration portfolio manager. Prior to joining Midstates Petroleum in 2012, Mr. Matejka had been a Sr. District engineer with Samson Resources, responsible for the evaluation of Samson's Haynesville shale asset. At Midstates Mr. Matejka headed the engineering evaluation of both the Eagle Energy and Panther Energy acquisitions, prior to transitioning into the role of Director—Corporate Reserves. Mr. Matejka graduated from the University of Leoben, Austria as Diplom Ingenieur in Petroleum Business in 1998 and from the University of Oklahoma in 2001 with a Master of Science Degree in Petroleum Engineering. Furthermore Mr. Matejka holds an MBA from Heriot-Watt University, UK. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, the reserve report is reviewed by our senior management with representatives of our independent reserve engineers and internal technical staff.

        In connection with our annual evaluation of the effectiveness of our internal control over financial reporting for the year ended December 31, 2013, we determined that, as of December 31, 2013, we did not maintain effective internal control over the accuracy and valuation of oil and gas reserves estimates. During the year ended December 31, 2014, we have made changes in our internal control over financial reporting (specifically over the preparation of oil and gas reserve estimates) that have materially affected our internal control over financial reporting. For the year ended December 31, 2014, management concluded that the material weakness over the preparation of oil and gas reserve estimates (previously identified during the year ended December 31, 2013) had been remediated and that the Company maintained effective internal control over the accuracy and valuation of the oil and gas estimates.

Production, revenues and price history

        Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during the past decade. However, the economic slowdown during the second half of 2008 and through 2009 reduced this demand. Demand for oil increased during 2010, 2011 and 2012, but demand for natural gas has remained sluggish and the price of natural gas has remained relatively depressed due to increasing supplies from shale plays. Additionally, the price of oil substantially declined in the fourth quarter of 2014 due to a variety of macroeconomic factors, including increasing supply, strengthening of the US dollar and forecasts of slower worldwide economic growth. Commodity prices have varied substantially over the past year. The spot natural gas prices during 2014 ranged from a high of $8.15 to a low of $2.99 per MMBtu and the spot oil prices during 2014 ranged from a high of $107.95 to a low of $53.45 per Bbl. Thus far in 2015, commodity prices have continued to be depressed and volatile, with spot natural gas prices ranging from a high of $3.32 to a low of $2.62 per MMBtu and the spot oil prices ranging from a high of $53.56 to a low of $44.08 per Bbl through March 2, 2015. Demand is impacted by general economic conditions, weather and other seasonal conditions. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A continued substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access

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capital markets. The following table sets forth information regarding oil, NGLs and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2014, 2013 and 2012. For additional information on price calculations, see information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operation."

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        The following table sets forth information regarding oil, NGLs and natural gas daily production for each of the fields that represented more than 15% of our estimated total proved reserves as of December 31, 2014:

Productive Wells

        The following table presents our total gross and net productive wells as of December 31, 2014:

        Gross wells are the number of wells in which a working interest is owned, and net wells are the total of our fractional working interest owned in gross wells.

Acreage

        The following table sets forth certain information regarding the developed and undeveloped acreage in which we have a controlling interest as of December 31, 2014 for each of our operating areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

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Undeveloped Acreage Expirations

        The following table sets forth the number of gross and net undeveloped acres as of December 31, 2014 that will expire over the next three years by operating area unless production is established within the spacing units covering the acreage or we make additional lease rental payments prior to the expiration dates:

        Approximately 6% of our net acreage, including acreage under option, was acquired in 2014, with the majority of such leases under three year primary term leases. In addition, our typical lease terms along with unit regulatory rules generally provide us flexibility to continue lease ownership through either establishing production or actively drilling prospects. Because of our limited capital resources and reduced activity levels in the Anadarko Basin and Gulf Coast, we may allow leasehold rights on acreage not held by production to expire in these areas, which could reduce our future drilling opportunities. Based on current pricing and current drilling plans, we impaired the remaining Anadarko basin unevaluated property to the full cost pool during the fourth quarter of 2014.

Drilling Activity

        The following table summarizes our drilling activity for the years ended December 31, 2014, 2013 and 2012. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

        As of December 31, 2014, there were four gross (and net) development wells currently drilling; no exploratory wells were being drilled.

        After peaking in 2013, our drilling activity has decreased over the last several months. At December 31, 2014 we were operating six drilling rigs on our properties and we are currently operating four drilling rigs. Our recent drilling activity has primarily focused on development and delineation and appraisal of our primary operating areas in the Mississippian and Anadarko Basin. In addition to the drilling activity listed above, a portion of our capital program over the last three years has also been focused on re-entering and recompleting productive zones in existing wellbores. For the year ended

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December 31, 2014, we did not have any operated wells that were deemed dry holes. However, as part of our exploration agreement with PetroQuest (discussed above), one well was drilled and deemed a dry hole in the Lower Wilcox during the first quarter of 2015.

Marketing and Major Customers

        We sell our oil, NGLs and natural gas to third-party purchasers. We are not dependent upon, or contractually limited to, any one purchaser or small group of purchasers other than in our Mississippian region, where a portion of our natural gas production is dedicated to one purchaser for the economic life of the relevant assets. For the year ended December 31, 2014, Plains Marketing, Semgas, Phillips66 and Valero Marketing accounted for 28%, 18%, 15% and 12% of our revenues, respectively. For the year ended December 31, 2013, ConocoPhillips, Chevron, Gulfmark, Semgas and Valero Marketing accounted for 28%, 16%, 13%, 12%, and 11% of our revenues, respectively. For the year ended December 31, 2012, Chevron, Gulfmark and Targa accounted for 41%, 32% and 10% of our revenues, respectively. Due to the nature of oil, natural gas and NGL markets, and because we sell our oil production to purchasers that transport by truck rather than by pipelines, we do not believe the loss of a single purchaser or a few purchasers would materially adversely affect our ability to sell our production.

        We are party to a gas purchase, gathering and processing contract (as amended and effective June 1, 2013) in the Mississippian Lime region, which includes certain minimum natural gas and NGL volume commitments. To the extent we do not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, we would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee of roughly $0.08 to $0.125 per gallon (subject to annual escalation). The NGL volume commitments range from 2,800 Bbls to 5,780 Bbls per day for each monthly accounting period over the remaining term of the contract. Additionally, we are obligated to deliver a total of 38,100,000 MMBtus and 76,200,000 MMBtus during the first 30 months and 60 months of the contract, respectively. During the first 30 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu. During the first 60 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu, provided that we would receive volumetric credit for any deficiency payment made after the initial 30 months. As of January 31, 2015, we have delivered 62,573,054 MMBtu. We are currently delivering at least the minimum volumes required under these contractual provisions and do not expect to incur any future volumetric shortfall payments during the term of this contract.

Title to Properties

        As is customary in the oil and natural gas industry, we initially conduct a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect defects affecting those properties, we are typically responsible for curing any such defects at our expense. We generally will not commence drilling operations on a property until we have cured known material title defects on such property. We have reviewed the title to substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on the most significant properties and, depending on the materiality of properties, we may obtain a title opinion or review or update previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens for current taxes and

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other burdens which we believe do not materially interfere with their use or affect our carrying value of the properties.

Seasonality

        Generally, demand for oil and natural gas decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

        Winter weather conditions can limit or temporarily halt our drilling and producing activities and other oil and natural gas operations, including gas processing, access to electricity and transportation. Additionally, once production comes back online following a cessation due to weather, it may take a period of time before production from a well reaches the level it was at prior to the cessation. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increased costs or delay or temporarily halt our operations.

Competition

        The oil and natural gas industry is highly competitive. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas companies and individual producers and operators. Many of these competitors are large, well established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and successfully consummate transactions in a highly competitive environment.

Regulation of the oil and natural gas industry

        Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and produced during operations and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

        Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently

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amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission ("FERC") and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of transportation and sale of oil

        Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. For our oil production, all of that transportation is currently via truck and we do not rely on interstate or intrastate pipelines.

Regulation of transportation and sales of natural gas

        Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

        FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines' traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC's orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

        The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach that FERC has historically maintained will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

        The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission ("CFTC") and the Federal Trade Commission ("FTC"). Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition to the anti-market manipulation laws, FERC has also issued regulations

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to increase market transparency. Pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, to report on May 1 of each year aggregate volumes of natural gas purchased or sold at wholesale in the previous calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order No. 704.

        Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC's determinations as to the classification of facilities is done on a case by case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of production

        The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

        The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Other federal laws and regulations affecting our industry

        Energy Policy Act of 2005.    On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 ("EPAct 2005"). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add

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an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC's NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

        Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1.0 million per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act.

        In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission ("CFTC") to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation.

        Additional proposals and proceedings that might affect the oil and natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Environmental and occupational health and safety regulation

        Our oil and natural gas exploration, development and production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing occupational safety and health, the emission or discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency ("EPA"), analogous state agencies, and, in certain instances, citizens' groups, have the power to enforce

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compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close waste pits and plug abandoned wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of injunctions prohibiting some or all of our operations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

        The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in federal or state environmental laws and regulations or re-interpretation of applicable enforcement policies that result in more stringent and costly well construction, drilling, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements or that limit or otherwise restrict the emission of certain pollutants or organic compounds from wells or surface equipment could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that we will be able to remain in compliance in the future with existing or any new laws and regulations or that future compliance with such laws and regulations will not have a material adverse effect on our business and operating results.

        The following is a summary of the more significant existing environmental, and occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes

        The Comprehensive Environmental Response, Compensation, and Liability Act, as amended ("CERCLA"), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed of or arranged for the disposal of the hazardous substances at a site where a release has occurred. Under CERCLA, these "responsible parties" may be subject to strict, joint and several liability for the costs of removing and cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to

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file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. Despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

        We also are subject to the requirements of the Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous and nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although RCRA currently exempts certain drilling fluids, produced waters, and other wastes associated with exploration, development and production of oil and natural gas from regulation as hazardous wastes, we can provide no assurance that this exemption will be preserved in the future. From time to time the EPA and analogous state agencies have considered repealing or modifying this exemption, and citizens' groups have also petitioned the agency consider its repeal. Repeal or modification of this exemption or similar exemptions under state law could have a significant impact on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted. In any event, at present, these excluded wastes are subject to regulation as RCRA nonhazardous wastes. In addition, we generate petroleum hydrocarbon wastes and ordinary industrial wastes in the course of our operations that may become regulated as RCRA hazardous wastes if such wastes have hazardous characteristics.

        We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by the third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.

Air emissions

        The Clean Air Act, as amended ("CAA"), and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAP") programs. With regards to production

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activities, these final rules require, among other things, that certain of the natural gas wells being fractured or re-fractured must use reduced emission completions, also known as "green completions," with or without combustion devices, beginning in January 2015. These regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. If the EPA lowers the ozone standard, states could be required to implement more stringent regulations, which could, among other things, require installation of new emission controls on some of the drilling program's equipment, result in longer permitting timelines, and significantly increase the partnership's capital expenditures and drilling program's operating costs, which could adversely impact our business. Compliance with any one or more of these requirements could increase our costs of development and production, which costs could be significant.

Climate change

        Based on the EPA's determination that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climatic changes, the agency has adopted regulations under existing provisions of the federal CAA that, among other things, establish pre-construction and operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain permits for their GHG emissions also will be required to meet "best available control technology" standards that typically will be established by the states. In addition, the EPA has adopted regulations requiring the monitoring and annual reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. These EPA regulations could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. We cannot predict which areas, if any, the EPA may choose to regulate with respect to GHG emissions next.

        While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, such requirements could require us to obtain permits for our GHG emissions, install costly emission controls, pay fees on the emissions data, and adversely affect demand for the oil and natural gas that we produce. For example, in January 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Administration's efforts to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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Water discharges and fluid injections

        The Federal Water Pollution Control Act, as amended (the "Clean Water Act"), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities, including oil and natural gas production facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

        The Oil Pollution Act of 1990, as amended ("OPA"), amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.

        Fluids resulting from oil and natural gas production, consisting primarily of salt water, are disposed by injection in belowground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control ("UIC") program established under the federal Safe Drinking Water Act and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While we believe that our disposal well operations substantially comply with requirements under the UIC program, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into belowground disposal wells triggers seismic activity in certain areas, including Texas and Oklahoma, where we operate. In response to these concerns, in October 2014, the Texas Railroad Commission ("TRC") published a final rule governing permitting or re-permitting of disposal wells that will require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs. Similar rules may be expected to be promulgated by the Oklahoma Corporation Commission (OCC). The OCC recently posted a guidance for wells injecting into the Arbuckle formation. OCC is watching for indications that salt water injection may be contributing to significant

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seismic events and has recently temporarily shut in another Producer's water disposal well due to a nearby 4.0 magnitude earthquake.

Hydraulic fracturing activities

        Hydraulic fracturing is an important and common industry practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final CAA regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management ("BLM") issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act, as amended ("SDWA") and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including Louisiana, Texas and Oklahoma, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, such as the State of New York announced in December 2014. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

        In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. For example, the White House Council on Environmental Quality is coordinating an administration wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and is expected to issue a draft report for public comment and peer review sometime in the first half of 2015. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

        To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We only use qualified contractors to perform hydraulic fracturing activities at our properties who have experience performing fracturing services on similar properties and who have demonstrated to our satisfaction that they employ appropriate safeguards to ensure that hydraulic fracturing will be performed in a safe and environmentally protective manner. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability

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insurance policies would cover third party claims related to hydraulic fracturing operations conducted by third parties and associated legal expenses in accordance with, and subject to, the terms and coverage limits of such policies.

Endangered Species Act considerations

        The federal Endangered Species Act, as amended ("ESA"), restricts exploration, development and production activities that may affect endangered and threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits the taking of endangered species. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service ("FWS") is required to make a determination on a listing of species as endangered or threatened under the ESA by no later than completion of the agency's 2017 fiscal year. For example, in March 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas and Oklahoma, where we conduct operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies ("WAFWA"), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken's habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken's habitat. The designation of the lesser prairie chicken or other previously unprotected species as endangered or threatened in areas where underlying operations are conducted or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on our ability to develop and produce reserves, which costs, delays or limitations may be significant.

OSHA

        We are subject to the requirements of the federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Employees

        As of December 31, 2014, we employed 183 people, including 42 technical (geosciences, engineering, land), 76 field operations, 59 corporate (finance, accounting, planning, business development, legal, office management) and six management.

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Offices

        We currently lease approximately 57,000 square feet of office space in Tulsa, Oklahoma at 321 South Boston Avenue, Suite 1000, where our principal offices are located. The lease for our Tulsa office expires in 2021. We also lease approximately 41,200 square feet of office space in Houston, Texas at 4400 Post Oak Parkway, Suite 2600. The lease for our Houston office expires in 2018. Due to the announced closure of our Houston office, we are currently working to sublet our Houston office space. We also lease one field office in Louisiana, one in Dacoma, Oklahoma and one in Perryton, Texas.

Legal Proceedings

        From time to time, we are party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. See Note 15—Commitments and Contingencies—Litigation in the Notes to the Unaudited Consolidated Financial Statements included in this prospectus.

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MANAGEMENT

        The Board of Directors and the executive officers of the Company are:

        The Company's Board of Directors currently consists of seven members. Other than the director who is elected by the holders of the Preferred Stock (which is currently unfilled), the Company's directors serve for a one year term. Directors may be removed from office either for or without cause upon the affirmative vote of the holders of at least 75% of the outstanding shares of stock of the Company entitled to vote generally for the election of directors.

        Set forth below is biographical information about each of the Company's executive officers, directors and nominees for director.

        Frederic F. Brace has served as our Interim President and Chief Executive Officer since March 18, 2015 and as a member of our Board of Directors since March 9, 2015. Mr. Brace has over twenty years of experience in business management and board representations. He is currently Chairman and Chief Executive Officer of Beaucastel LLC and Sangfroid Advisors Ltd. Previously, Mr. Brace worked for Niko Resources, Ltd., an oil and gas company, from August 2013 to December 2014 serving first as Senior Advisor and then as President of the company. From 1988 to 2008, Mr. Brace worked at the UAL Corporation (now United Continental Holdings, Inc.), the parent company of United Airlines, Inc. and Continental Airlines, Inc., where he served as Executive Vice President and Chief Financial Officer of UAL Corporation and United Airlines, Inc. from 2002 to 2008. Mr. Brace is a member of the board of directors of Anixter International and Standard Register. He has also served on the board of numerous public and private companies. He received his BS in Industrial Engineering from the University of Michigan in 1980 and his MBA with a specialization in finance from the University of Chicago Graduate School of Business in 1982. We believe Mr. Brace's knowledge of the energy industry and expertise in representing public and private companies will allow him to provide valuable insights to our Board of Directors.

        Thomas C. Knudson has served as a member of our Board of Directors since May 2013 and as Chairman of the Board of Directors since April 2014. Mr. Knudson has served as the Non-Executive Chairman of Bristow Group Inc. (NYSE: BRS) since August 2006 and as a Director of Bristow since June 2004. Mr. Knudson has been president of Tom Knudson Interests, which provides consulting services in energy, sustainable development, and leadership, since its formation in 2004. Following seven years of active duty as a U.S. Naval aviator and an aerospace engineer, he joined Continental Oil

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Company (Conoco) in 1975 and retired in 2004 from Conoco's successor, ConocoPhillips, as Senior Vice President of Human Resources, Government Affairs and Communications and as a member of ConocoPhillips' management committee. He was the founding Chairman of the Business Council for Sustainable Development in both the United States and the United Kingdom. Mr. Knudson served as a Director of NATCO Group, Inc. from April 2005 to November 2009, Williams Partners L.P. from November 2005 to September 2007, and MDU Resources Group Inc. (NYSE: MDU) from November 2008 to April 2014. He served as a Trustee of the Episcopal Seminary of the Southwest since February 2012 and as a member of the National Council of Methodist Neurological Institute since October 2011. Mr. Knudson has a bachelor's degree in aerospace engineering from the U.S. Naval Academy and a master's degree in aerospace engineering from the U.S. Naval Postgraduate School. We believe Mr. Knudson's extensive knowledge and expertise in the energy industry will allow him to provide valuable insights to our Board of Directors.

        George A. DeMontrond has served as a member of our Board of Directors since April 2014. Mr. DeMontrond is a Vice President with First Reserve Corporation ("First Reserve"), a global energy-focused private equity and infrastructure investment firm, and joined the firm in 2007. Mr. DeMontrond's responsibilities at First Reserve range from deal origination and structuring to due diligence, execution and monitoring, with a particular emphasis on the reserves sector. Prior to joining First Reserve, Mr. DeMontrond served as an Investment Banking Analyst in the Energy, Utilities & Chemicals Group at Deutsche Bank Securities Inc. He holds a bachelor's degree from Rice University. We believe Mr. DeMontrond's extensive energy industry background brings important experience and skill to our Board of Directors.

        Alan J. Carr has served as a member of our Board of Directors since March 9, 2015. Mr. Carr is an investment professional with twenty years of experience working from the principal and advisor side on complex, process-intensive financial situations. Mr. Carr is the founder of Drivetrain Advisors, a fiduciary services firm that supports the investment community in legally- and process-intensive investments as a representative, director, or trustee. Prior to founding Drivetrain Advisors in 2013, Mr. Carr was a Managing Director at Strategic Value Partners, LLC ("Strategic Value Partners"), where he led financial restructurings for companies in North America and Europe, working in both the US and Europe over nine years. Prior to joining Strategic Value Partners, Mr. Carr was a corporate attorney at Skadden, Arps, Slate, Meagher & Flom. Mr. Carr currently serves on the board of directors of Tanker Investments Ltd. and Brookfield DTLA Fund Office Trust Investor Inc. Mr. Carr has experience serving on boards of a variety of companies in North America, Europe and Asia. He received his B.A. in Economics and Sociology from Brandeis University in 1992 and his J.D. from Tulane Law School in 1995. We believe Mr. Carr's extensive financial expertise and experience in representing public and private companies in complex financial situations and brings important experience and skill to our Board of Directors.

        Bruce Stover has served as a member of our Board of Directors since March 18, 2015. Mr. Stover has over forty years of experience in the oil and gas industry and has an extensive background in mergers and acquisitions as well as global operations and business development. Mr. Stover has served on the board of directors of the Bristow Group, Inc. since 2009 and as Chairman of the Compensation Committee of such board since 2012. Prior to joining the board of Bristow Group, Inc., he was a founding member of the management team of Endeavor International Corporation, where he served as Executive Vice President, Operations and Business Development, from 2003 to 2010. Before serving at Endeavor International Corporation, Mr. Stover was Senior Vice President, Worldwide Business Development for Anadarko Petroleum Corporation responsible for evaluating and securing domestic and international business opportunities. While there, Mr. Stover also served as President and General Manager of Anadarko Petroleum Corporation's Algerian subsidiary. He began his career as an engineer with Amoco Production Company. We believe Mr. Stover's experience in the energy industry and

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expertise in representing public and private companies brings important experience and skill to our Board of Directors.

        Robert E. Ogle has served as a member of our Board of Directors since March 18, 2015. Mr. Ogle has been a certified public accountant for over thirty-five years with experience in the upstream and downstream oil and gas industries, retail, airline and service industries, representing debtors, creditors, investors and governmental agencies. Mr. Ogle is currently a Senior Advisor with The Claro Group. Prior to joining The Claro Group, he was a founder and Chief Financial Officer for Ute Energy LLC from 2005 to 2009. Before serving there, Mr. Ogle was the Director of Corporate Recovery Services at Huron Consulting and prior to joining Huron Consulting was a Corporate Recovery Services Partner at Arthur Andersen, where he started their corporate recovery services practice in Houston. While at Arthur Andersen, Mr. Ogle provided services to Link Energy, Continental Airlines, Delta Airlines, United Airlines, Edge Petroleum Corporation, Orion Refinery, Entergy and many others. Mr. Ogle co-founded the Houston Chapter of the Turnaround Management Association. We believe Mr. Ogle's extensive financial expertise and experience in representing public and private companies brings important experience and skill to our Board of Directors.

        John Mogford has served as a member of our Board of Directors since March 2011. Mr. Mogford joined First Reserve as Operating Partner in 2009 and was a Managing Director based in London through April 1, 2015. He now serves as a consultant to First Reserve. He provides direct operational support and guidance to First Reserve's portfolio company executives as well as strategic advice to First Reserve investment teams. Prior to joining First Reserve, Mr. Mogford spent thirty-two years at BP, mainly in upstream, most recently as the Executive Vice President for Refining. He served as one of 10 members of BP's Executive Committee. He holds a degree from Sheffield University and business qualifications from INSEAD and Stanford Universities. We believe Mr. Mogford's extensive energy industry background, particularly his expertise in exploration and production operations, brings important experience and skill to our Board of Directors.

        Nelson M. Haight has served as our Executive Vice President and Chief Financial Officer since January 2015, and previously served as Senior Vice President and Chief Financial Officer from January 2014 through January 2015, and as our Chief Accounting Officer from August 2013 through January 2014. Mr. Haight previously served as our Vice President and Controller from December 2011 to August 2013. Mr. Haight is a Certified Public Accountant and prior to joining the Company, Mr. Haight was a partner with the audit firms of GBH CPAs from November 2008 to December 2011 and Malone Bailey, PC from July 2007 to November 2008. Prior to those positions, Mr. Haight served in a variety of public accounting and finance roles and began his career in 1988 with Arthur Andersen and Co. Mr. Haight holds a bachelor's degree and a master's degree in public accounting from the University of Texas at Austin.

        Mitchell G. Elkins has served as our Executive Vice President of Operations since January 2015 after his previous role of Vice President of Drilling and Completions, which he held since 2012. Prior to joining the Company, Mr. Elkins worked as the International Drilling Manager for Transatlantic in Instanbul, Turkey from May 2011 through January 2012 and the Drilling and Completions manager for Apache in their Australian operations from July 2006 through April 2011. Prior to that, Mr. Elkins held a variety of roles for Unocal as well as Apache, and also owned a project management company supporting clients such as Apache, Chevron, Perenco, Shell and others in international operations. Mr. Elkins holds a BS in Control Engineering with a Petroleum Production Base from the University of Texas—Permian Basin.

        Mark E. Eck has served as our Executive Vice President and Chief Operating Officer since December 2014. Prior to joining Midstates, Mr. Eck most recently served with Samson Resources Company ("Samson"), an oil and gas exploration and production company, as Vice President, Business Development from December 2012 to October 2013, as Vice President, Operations and Midstream

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from March 2012 to December 2012 and as General Manager, Haynesville from March 2010 to February 2012. Prior to joining Samson, Mr. Eck served as the Business Development Manager for SM Energy Company, an oil and gas exploration and production company, from March 2008 to February 2010 and their Manager of Supply Chain Management from April 2007 to February 2008. Before SM Energy, Mr. Eck was the Business Development Manager and Project Engineer for Springfield Underground from 2000 to 2007 and served in various positions with ARCO Oil & Gas Company from 1981 to 2000. Mr. Eck received his Bachelor's degree in Mechanical Engineering from Missouri-Rolla University in 1980.

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

Compensation Discussion and Analysis

        This compensation discussion and analysis, or CD&A, provides information about our compensation objectives and policies for (i) any individual who served as our Chief Executive Officer or our Chief Financial Officer during 2014, (ii) our three other most highly compensated executive officers, or, if fewer than three executive officers are employed by us on the last day of the year, as was the case in 2014, such lesser number of executive officers, and (iii) any former executive officer who would have been one of our three most highly-compensated executive officers during 2014 but for the fact the executive was no longer providing services to us at the end of 2014. We refer to the aforementioned individuals throughout this discussion as the "Named Executive Officers" and their names, titles and positions are as follows:

        Effective January 6, 2014, Mr. Mitchell resigned from employment with the Company and Mr. Haight was promoted to the position of Senior Vice President and Chief Financial Officer. Mr. Haight was promoted to Executive Vice President and Chief Financial Officer as of January 1, 2015. Mr. Crum's employment with the Company terminated effective March 31, 2014 and Dr. Hill was appointed Interim President and Chief Executive Officer, effective March 31, 2014. On March 4, 2015, Dr. Hill notified the Board of his intent to resign from his current position as interim President and Chief Executive Officer following the filing of the Company's annual report on Form 10-K, and subsequently resigned from this position on March 18, 2015. Furthermore, Dr. Hill resigned from the Board effective as of March 9, 2015. Dr. Hill was available to provide transition services to us until April 30, 2015. On March 18, 2015, Frederic (Jake) F. Brace was appointed as our new Interim President and Chief Executive Officer.

        This CD&A focuses primarily on the information in the tables below and related footnotes, as well as the supplemental narratives, relating to the fiscal year ended December 31, 2014.

2014 Business Highlights

        We believe that our executive management team created significant value for our stockholders in 2014. The following are key highlights of our achievements during fiscal year 2014:

•

Increased average daily production 34% year-over-year to 32,137 Boepd in 2014, up from 23,927 Boepd in 2013.



•

Achieved record Adjusted EBITDA, before acquisition and transaction costs, of $474.1 million in 2014, up 43.3% from $330.8 million in 2013.



•

Completed and placed on production 120 gross (98 net) wells during 2014.



•

Increased total estimated net proved oil and natural gas reserves to 153.7 MMBoe at December 31, 2014, a 20% increase over year-end 2013 total estimated net proved reserves.

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Compensation Program Philosophy and Objectives

        Our future success and the ability to create long-term value for our stockholders depends on our ability to attract, retain and motivate some of the most qualified individuals in the oil and gas industry. Our compensation program is designed to reward performance that supports our long-term strategy and the achievement of our short-term goals. We believe that compensation should:

•

help to attract and retain the most qualified individuals in the oil and gas industry by being competitive with compensation paid to persons having similar responsibilities and duties in other companies in the same and closely related industries;



•

align the interests of the individual with those of our stockholders and motivate long-term value creation;



•

be directly tied to the attainment of annual performance targets and reflect the Named Executive Officer's individual contribution thereto;



•

pay for performance, whereby an individual's total direct compensation is heavily influenced by company performance; and



•

reflect the unique qualifications, skills, experience and responsibilities of each individual.

Setting Executive Officer Compensation

        Our Compensation Committee makes all compensation decisions related to our Named Executive Officers. For each fiscal year, our Chief Executive Officer reviews our Named Executive Officers' current compensation and makes a recommendation to our Compensation Committee regarding overall compensation structure and individual compensation levels for each Named Executive Officer other than himself.

        As discussed in greater detail throughout this CD&A, our Compensation Committee met numerous times during 2014 to review and discuss executive compensation matters with respect to 2014. Our Compensation Committee intends to set our Named Executive Officer's base salary compensation at approximately the 50th percentile within our peer group and to provide our Named Executive Officers with an opportunity to earn compensation up to approximately the 75th percentile for total direct compensation, subject to target performance metrics being met or exceeded. Although our Compensation Committee reviews survey information as a frame of reference, ultimately the compensation decisions take into consideration, in material part, factors such as a particular Named Executive Officer's contribution to our financial performance and condition, as well as such officer's qualifications, skills, experience and responsibilities. Our Compensation Committee considers outside factors as well, such as shortages in the industry of qualified employees for such positions, recent experience in the marketplace, and the elapsed time between the surveys used and when compensation decisions are made. In light of these qualitative and other considerations, the base salary of a particular officer may be greater or less than the 50th percentile of our peers and total direct compensation may be greater or less than the 75th percentile of our peers and, if lower than these levels, our Compensation Committee recognizes that the compensation of certain of our executive officers may continue to build to these levels.

        Our Compensation Committee reviews our executive compensation program on an annual basis. During the first quarter of 2014, our Compensation Committee reviewed recommendations regarding changes to 2014 compensation for our Named Executive Officers and, following consultation with management, in February 2014, our Compensation Committee approved certain changes to our executive compensation program for 2014 that are described in the following sections of this CD&A.

        Benchmarking and Peer Group.    For 2014, our Compensation Committee met with members of our management team and representatives from Longnecker, our compensation consultant, to select a

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group of companies as a "peer group" for executive and director compensation analysis purposes. This peer group was then used for purposes of developing the recommendations presented to our Board of Directors for 2014 compensation packages for our executive officers and our non-employee directors that receive compensation. The oil and gas companies that comprise this peer group were selected primarily because they (i) have similar annual revenue, assets, market capitalization and enterprise value as us and (ii) potentially compete with us for executive-level talent. In light of these considerations, it was determined that certain changes to the 2013 peer group were necessary in order to establish an appropriate peer group for 2014 to reflect changes in the Company's annual revenue, assets, market capitalization and enterprise value. The 2014 peer group for compensation purposes consists of:

•

Approach Resources, Inc.



•

Bill Barrett Corp.



•

Clayton Williams Energy, Inc.



•

Endeavour International Corporation



•

EPL Oil & Gas, Inc.



•

Forest Oil Corporation



•

Goodrich Petroleum Corp.



•

Halcon Resources Corporation



•

Magnum Hunter Resources Corp.



•

PDC Energy, Inc.



•

Penn Virginia Corporation



•

Stone Energy Corp.



•

Swift Energy Co.

        Longnecker compiled compensation data for the peer group from a variety of sources, including proxy statements and other publicly filed documents. Longnecker also provided published survey compensation data from multiple sources. This compensation data was then used to compare the compensation of our Named Executive Officers to individuals with comparable duties and responsibilities at companies within our peer group and in the survey data. As noted above, our Compensation Committee generally targets base salary levels for our Named Executive Officers at roughly the 50th percentile of our peer group, and annual cash and long-term incentive awards so that our Named Executive Officers have the opportunity to realize, in future years, total direct compensation up to the 75th percentile of our peer group based on strong company performance.

        For subsequent years, our Compensation Committee will review and re-determine on an annual basis the composition of our peer group so that the peer group will continue to consist of appropriate peer companies, taking into account the factors previously mentioned.

        Role of the Compensation Consultant.    Our Compensation Committee's charter grants the Committee the sole authority to retain, at our expense, outside consultants or experts to assist it in its duties. For 2014, our Compensation Committee engaged Longnecker to advise it with respect to executive compensation matters, including development of the annual compensation peer group and an annual review and evaluation of our executive and director compensation packages generally, based on, among other things, survey data and information regarding general trends. Representatives from Longnecker periodically meet with our Compensation Committee throughout the year and advise our Compensation Committee with regard to general trends in director and executive compensation,

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including (i) competitive benchmarking; (ii) incentive plan design; (iii) peer group selection; and (iv) other matters relating to executive compensation. In addition, Longnecker provides our Compensation Committee and management with survey compensation data regarding our compensation peer group for each fiscal year. Longnecker did not provide any services to us or to management other than the services provided to the Compensation Committee.The Compensation Committee has concluded that we do not have any conflicts of interest with Longnecker.

Elements of Our Compensation and Why We Pay Each Element

        The compensation program for our Named Executive Officers is comprised of the following five elements:

•

base salary;



•

annual performance-based cash incentive awards;



•

long-term equity-based compensation (including restricted stock awards);



•

retention awards; and



•

other employee benefits.

        Base Salary.    Base salary is the fixed annual compensation we pay to each Named Executive Officer for performing specific job responsibilities. It represents the minimum income a Named Executive Officer may receive in any year. We pay each Named Executive Officer a base salary in order to:

•

recognize each executive officer's unique value and contributions to our success in light of salary norms in the industry and the general marketplace;



•

remain competitive for executive-level talent within our industry;



•

provide executives with sufficient, regularly-paid income; and



•

reflect position and level of responsibility.

        In setting annual base salary amounts, our Compensation Committee aims to pay base salaries that, by position, are in approximately the 50th percentile of our peer group, although the Compensation Committee also takes into consideration factors such as the particular officer's contribution to our financial performance and condition, as well as the officer's qualifications, skills, experience and responsibilities.

        At its February 2014 meeting, our Compensation Committee reviewed data provided by Longnecker with respect to our 2014 compensation peer group and approved increases to the base salaries of certain of our Named Executive Officers for fiscal year 2014. These increases were primarily implemented so that the base salaries of our Named Executive Officers would more closely align with the 50th percentile of our 2014 compensation peer group. In light of the additional responsibilities of Messrs. Burleigh and Newstrom in a variety of areas throughout our organization, their annual base salaries for 2014 remain above the 50th percentile of base salaries for other officers with similar positions at companies within our 2014 compensation peer group. In addition, the base salary increase for Mr. Haight reflects his promotion to Senior Vice President and Chief Financial Officer in January 2014. As such, the 2014 base salaries of our Named Executive Officers as compared to the

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base salary rates of officers with like positions at the 50th percentile of our peer group were set as follows:

        Additionally, in connection with Dr. Hill's appointment as Interim President and Chief Executive Officer on March 31, 2014, the Compensation Committee reviewed data provided by Longnecker with respect to the compensation of interim chief executive officers of similarly situated companies and approved cash compensation of $100,000 per month to Dr. Hill for assuming the role. During 2014, Dr. Hill participated in the Company's annual performance-based cash incentive bonus program but did not receive any equity grants under the LTIP related to his service as Interim President and Chief Executive Officer. Dr. Hill retained his prior compensation package for his service on the Company's Board of Directors, which includes an annual cash retainer in the amount of $50,000 and an award of restricted stock equal to a number of shares having a value of approximately $125,000 on the date of grant, under the terms of the LTIP.

        Annual Performance-Based Cash Incentive Awards.    We have historically utilized, and expect to continue to utilize, performance-based annual cash incentive awards to reward achievement of specified performance goals for the Company as a whole with a time horizon of one year or less. We include an annual performance-based cash incentive award as part of our compensation program because we believe this element of compensation helps to:

•

motivate management to achieve key annual corporate objectives, and



•

align executives' interests with our stockholders' interests.

        Amounts paid under the performance-based annual cash incentive program are paid in the Compensation Committee's sole discretion. The Compensation Committee takes into account several quantitative and qualitative factors, including the achievement of pre-established goals or metrics, which we call "Key Performance Indicators," or "KPIs," when determining the amount of payment awarded to each Named Executive Officer. At the beginning of each year, our Chief Executive Officer develops a proposal for the annual performance metrics for that year. The Chief Executive Officer then presents his proposal to the Compensation Committee, which independently analyzes the proposed annual performance metrics, makes modifications as it sees fit, and then approves a final set of performance metrics for the year. The performance metrics are then presented to the Named Executive Officers and other members of senior management so that they fully understand the program and the goals for that particular year. In the event that the Company makes a material acquisition during the course of the

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year, the performance metrics may be adjusted by the Compensation Committee, in its discretion, to appropriately address any changes in the asset makeup of the Company post-acquisition.

        Under our annual bonus program, our performance goals serve less as a formula and more as guidelines for our Compensation Committee to utilize throughout the year to ensure that payment of compensation under the program is aligned with the achievement of our Company's goals and targets. The performance goals are only one factor utilized by our Compensation Committee, alongside a number of other subjective features, such as extenuating market circumstances, individual performance and safety performance, when determining actual amounts of awards. Our Compensation Committee retains the ability to apply discretion to awards based on extenuating market circumstances or individual performance and to modify amounts based on safety performance.

        If we achieve the target performance metric, the cash incentive awards are expected to be paid at target levels. In order to create additional incentive for exceptional company performance based on the metrics described above and the discretion of our Compensation Committee, awards can be paid up to a maximum percentage of the base salary designated for each Named Executive Officer, but it is not expected that payment at this level would occur in most years. We set threshold, target and maximum levels for the performance metrics to serve as a guideline for determining the actual bonus amounts earned by our Named Executive Officers for 2014. In setting the performance incentive metrics for 2014, our Compensation Committee considered the extent to which targets were met in prior years to ensure that the targets utilized are sufficiently challenging. In February 2014, the Compensation Committee established the target, threshold and maximum awards to our Named Executive Officers, as a percentage of base salary, as set out in the table below. Actual award amounts are dependent on performance relative to specified performance metrics and subject to the discretion of our Compensation Committee. Threshold, target and maximum award levels were not established for Dr. Hill but our Compensation Committee took into account all of the factors described below when setting the value of his 2014 annual bonus.

        In 2014, the Compensation Committee established five KPIs, in addition to an overall adjustment for safety and environmental performance that could increase bonuses awarded under the Bonus Plan by up to 25% in the event of extraordinary performance in that area or decrease the bonuses awarded under the Bonus Plan by up to 100% in the event of severe underperformance. The specific goals set by the Compensation Committee at the beginning of 2014 and the weight given to each are listed below.

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2014 Annual Performance-Based Bonus Plan

        Actual performance for each KPI for the fiscal year is measured and reviewed by the Compensation Committee during the first few months following the end of the fiscal year for which the annual bonus is earned. As noted above, while the Compensation Committee closely examines company and individual performance with respect to each KPI, the Compensation Committee retains the discretion to increase or decrease a Named Executive Officer's annual cash bonus despite KPI performance based on an overall qualitative assessment of the individual officer's performance.

        In February 2015, the Compensation Committee reviewed 2014 actual performance against each of the KPIs. The Company achieved (i) between the minimum and target performance for payout under the Production Volumes metric, (ii) below target performance under the Drilling and Completions Internal Rate of Return metric, (iii) above maximum performance under the All Sources Finding Costs metric, (iv) between the target and maximum performance under the Lease Operating Expense metric, and (v), at the target under Year End 2014 Liquidity metrics, which were established to focus primarily upon maintaining financial flexibility and improvement of debt metrics. The Compensation Committee did not increase or decrease the payout under the 2014 Bonus Plan for safety and environmental performance.

        Overall, the formulaic outcome based on the above KPI payouts called for a total payout under the 2014 Bonus Plan of approximately 95% of the target level. However, due to the current commodity price environment, the Compensation Committee established a total bonus pool under the 2014 Bonus Plan equal to 65% of the target awards of the participants in the plan. The Compensation Committee granted the Named Executive Officers awards in the following amounts, which are included in the "Non-Equity Incentive Plan Compensation" column of the "Summary Compensation Table" for 2014: Dr. Hill—$750,000; and Mr. Haight—$239,693. Our employment relationship with each of Messrs. Crum, Mitchell, Hebertson, Newstrom, and Burleigh terminated prior to the payment of the 2014 annual bonus. As such, Messrs. Crum, Mitchell and Newstrom did not receive payment of their 2014 annual bonus. Pursuant to the terms of their separation agreements with the Company, Messrs. Burleigh and Hebertson received annual bonus payments for 2014 in the following amounts: $188,500 for Mr. Burleigh; and $187,360 for Mr. Hebertson.

        Long-Term Equity-Based Incentives.    We believe a formal long-term equity incentive program is a valuable compensation tool and is consistent with the compensation programs of the companies in our peer group. We maintain a Long-Term Incentive Plan, or LTIP, which permits the grant of our stock, options, restricted stock, restricted stock units, phantom stock, stock appreciation rights and other awards, any of which may be designated as performance awards or be made subject to other conditions. We believe that long-term equity-based incentive compensation is an important component of our overall compensation program because it:

•

balances short and long-term objectives;

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•

aligns our executives' interests with the long-term interests of our stockholders;



•

rewards long-term performance relative to industry peers;



•

makes our compensation program competitive from a total remuneration standpoint;



•

encourages executive retention; and



•

gives executives the opportunity to share in our long-term value creation.

        Our Compensation Committee has the authority under the LTIP to award incentive equity compensation to our executive officers in such amounts and on such terms as the Committee determines appropriate in its sole discretion. To date, our long-term equity-based incentive compensation program has consisted solely of restricted stock awards. In 2014, the Compensation Committee made annual awards of restricted stock to our Named Executive Officers in February, a discretionary grant of restricted stock to Mr. Haight in connection with his promotion in January (the "Promotion Grant"), and loyalty and retention grants of restricted stock in June (described in more detail below in the subsection entitled "Loyalty and Retention Awards"). The Compensation Committee may determine in the future that different and/or additional award types are appropriate.

        We believe restricted stock awards effectively align our executive officers with the interests of our stockholders on a long-term basis and have retentive attributes. For 2014, our Compensation Committee made annual awards of restricted stock to our Named Executive Officers with an aggregate value at the time of grant equal to a specified percentage of the individual's base salary for the year.

        At its February 2014 meeting, our Compensation Committee approved annual restricted stock awards to our Named Executive Officers. The number of shares of restricted stock granted to each Named Executive Officer is as follows: (i) Mr. Haight—120,000 restricted shares, (ii) Mr. Burleigh—87,000 restricted shares (iii) Mr. Hebertson—96,000, and (iv) Mr. Newstrom—129,000 restricted shares. These awards were granted to our Named Executive Officers on February 21, 2014 and will vest as to one-third of the total award granted on each of the first three anniversaries of the date of grant, provided the award recipient remains continuously employed through the applicable vesting dates. The vesting of these awards will accelerate in full if the award recipient's employment is terminated due to either death or disability, and the awards are subject to the accelerated vesting provisions contained in any existing employment agreement. The awards to the Named Executive Officers were intended to represent a number of shares with an aggregate value at the time of grant approximately equal to the following percentages of base salary: (i) Mr. Haight—200%, (ii) Mr. Burleigh—150% (iii) Mr. Hebertson—200%, and (iii) Mr. Newstrom—200%. While a Named Executive Officer holds unvested restricted shares, he is entitled to all the rights of ownership with respect to the shares, including the right to vote the shares and to receive dividends thereon, which dividends must be paid within 30 days of the date dividends are distributed to our stockholders generally.

        Dr. Hill also received a grant of 25,000 restricted shares in February of 2014, but this award was made to him for services performed by him in his capacity as a director, prior to his assumption of the role of Interim President and Chief Executive Officer on March 31, 2014. This award vested in full on the first anniversary of the date of grant.

        In addition to the annual grants described above, our Compensation Committee made a Promotion Grant of 48,000 shares of restricted stock to Mr. Haight in January of 2014 in connection with his promotion. His award will vest over three years, and is subject to the same accelerated vesting provisions described above for the annual restricted stock grants.

        Messrs. Crum and Mitchell were not awarded any shares under the LTIP during 2014. In connection with Mr. Crum's separation from the Company in April 2014, the Compensation Committee accelerated the vesting of 150,000 of Mr. Crum's restricted shares that remained unvested pursuant to the terms of the applicable award agreement and the terms of the LTIP. All the unvested restricted

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stock held by each of Messrs. Mitchell, Hebertson, and Newstrom was forfeited at the time of their separation from the Company. In connection with Mr. Burleigh's termination of employment on January 1, 2015 and pursuant to the terms of his separation agreement, the vesting of 173,608 restricted shares, representing all of the unvested restricted shares held by Mr. Burleigh on the date of his termination, was accelerated.

        Loyalty and Retention Awards.    On June 6, 2014, the Compensation Committee approved the award of cash and equity retention awards to Messrs. Haight, Burleigh, and Hebertson. The cash retention awards granted were in the amounts of $90,000, $87,000, and $94,500 for Messrs. Haight, Burleigh, and Hebertson respectively, and are designed to pay out in three equal installments on each of July 1, 2014, January 2, 2015 and July 1, 2015, provided that the executive remains continuously employed (and not provide notice of intent to terminate employment) through each such date. The executives may be eligible to receive payment of the cash loyalty and retention awards in connection with a termination of employment by us without cause or by the executive for good reason.

        The equity retention awards granted on June 6, 2014 included 48,216, 46,608, and 50,625 shares of time-vested restricted stock for Messrs. Haight, Burleigh, and Hebertson, respectively, and will vest as to one-third of the award on each of the first three anniversaries of the date of grant, subject to the same conditions of vesting and acceleration described in the sub-section above entitled "Long-Term Equity-Based Incentives."

        Mr. Hebertson's separation agreement provided that he would be paid the two-thirds of his cash loyalty and retention award not yet paid as of his date of termination, in connection with his separation from service, which occurred in December of 2014. Mr. Burleigh received payment of the second tranche of the cash loyalty and retention award in January of 2015 and his separation agreement provided that he would be paid the final one-third of his cash loyalty and retention award not yet paid as of his date of termination, in connection with his separation from service, which occurred in January of 2015.

        Other Employee Benefits.    All of our full-time employees, including our Named Executive Officers, receive the same health and welfare benefits. The benefits include a 401(k) retirement program with a company match of up to 8% of base salary, health insurance, dental insurance, life and accidental death and dismemberment insurance, as well as long term disability insurance. We do not currently offer any other retirement or pension program as we feel that the compensation package offered to our Named Executive Officers provides compensation and incentives sufficient to attract and retain excellent talent without the addition of this benefit.

Employment Agreements

Named Executive Officer Employment Agreements

        Effective as of the completion of our initial public offering in April 2012, we entered into new employment agreements with certain of our executive officers, including all of our Named Executive Officers other than Dr. Hill (the "Employment Agreements"). Mr. Haight's employment agreement was amended at the time of his promotion to Senior Vice President and Chief Financial Officer. Other than the provisions of the agreements that survive termination, the employment agreements for Messrs. Crum, Mitchell, Burleigh, Hebertson, and Newstrom are no longer in effect. The material terms of the Employment Agreements are outlined below.

        The initial term of the Employment Agreements is two years with automatic extensions for additional one-year periods unless either party provides at least sixty days advance written notice of the intent to terminate the Employment Agreement. Each executive is entitled to four weeks of vacation each year during the term of the Employment Agreement. The Employment Agreement contains a confidentiality obligation on the part of the executive of indefinite duration and non-competition and non-solicitation obligations on the part of the executive for a period of one-year following his termination of employment with us for any reason other than death or disability.

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        Upon a termination of the executive's employment by us for Cause, by the executive without Good Reason, or due to death or disability during the term of the Employment Agreement, the executive is entitled to: (i) the portion of the executive's base salary accrued through the termination to the extent not previously paid, any expense reimbursement accrued and unpaid, any employee benefits pursuant to the terms of the applicable employee benefit plan, and any accrued but unused vacation (the "Accrued Obligations"), and (ii) any accrued or vested amount arising from the executive's participation in, or benefits under, any incentive plans (the "Accrued Incentives"), which amounts are payable in accordance with the terms and conditions of such incentive plans.

        Upon a termination of the executive's employment by us without Cause or by the executive for Good Reason during the term of the Employment Agreement, the executive is entitled to: (i) the Accrued Obligations, (ii) the Accrued Incentives, (iii) a lump-sum cash payment equal to the average annual bonus paid to the executive for the three immediately preceding completed fiscal years, and (iv) continued payment of the executive's base salary for a period of 18 months for Mr. Haight and 12 months for Messrs. Burleigh, Hebertson and Newstrom.

        Upon a termination of the executive's employment by us without Cause or by the executive for Good Reason during the term of the Employment Agreement and within twelve months of a change in control of us, the executive is entitled to: (i) the Accrued Obligations, (ii) the Accrued Incentives, (iii) accelerated vesting for all equity or equity based awards granted under the new long-term incentive plan that are not intended to be "qualified performance based compensation" within the meaning of Section 162(m) of the Internal Revenue Code (the "Code"), and (iv) a lump-sum cash payment equal to the product of (x) the highest annual bonus paid to the executive for the three immediately preceding completed fiscal years plus the highest base salary paid to the executive during the three years immediately preceding the change in control, multiplied by (y) 2.0.

        For purposes of the Employment Agreement, "Cause", in all material respects, means: (i) nonperformance by the executive of his obligations and duties, (ii) commission by the executive of an act of fraud, embezzlement, misappropriation, willful misconduct or breach of fiduciary duty against us or other conduct harmful or potentially harmful to our best interest, (iii) a material breach by the executive of the non-competition, non-solicitation, or confidentiality obligations under the Employment Agreement, (iv) the executive's conviction, plea of no contest or nolo contendere, deferred adjudication or unadjudicated probation for any felony or any crime involving fraud, dishonesty, or moral turpitude or causing material harm, financial or otherwise, to us, (v) the refusal or failure of the executive to carry out, or comply with, in any material respect, any lawful directive of our Board of Directors, (vi) the executive's unlawful use (including being under the influence) or possession of illegal drugs, or (vii) the executive's willful violation of any federal, state, or local law or regulation applicable to us or our business which adversely affects us.

        For purposes of the Employment Agreement, "Good Reason" means any of the following, but only if occurring without the executive's consent: (i) a material diminution in the executive's base salary, (ii) a material diminution in the executive's authority, duties, or responsibilities, (iii) the relocation of the executive's principal office to an area more than 50 miles from its location immediately prior to such relocation, or (iv) our failure to comply with any material provision of the Employment Agreement.

        Severance payments made under the Employment Agreement are contingent upon the executive's execution of a valid release of claims. Further, severance payments may be stopped and any payments already made must be repaid in the event the executive violates the confidentiality, non-competition or non-solicitation provisions of the Employment Agreement.

        Section 280G of the Code prevents a corporate payor from deducting certain large payments contingent upon a change in control ("parachute payments") from the corporation's gross income for federal tax purposes. In addition, Section 4999 of the Code imposes an excise tax on the recipient of an

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excess parachute payment equal to 20% of the amount of the excess parachute payment. In the event that Section 280G of the Code applies to any compensation payable to the executives, the Employment Agreement provides that we will either (x) reduce the payment(s) to an amount that is one dollar less than the amount that would trigger the application of Section 280G of the Code, or (y) make the full payment owed to the executive, whichever of (x) or (y) results in the best net after tax position for the executive. The Employment Agreements do not provide any obligation for us to pay a "gross-up" or make the executive whole for any excise or regular income taxes, including the excise taxes that may be due under Section 4999 of the Code.

Employment Agreement with Mr. Brace

        In connection with the appointment of Mr. Brace as interim President and Chief Executive Officer, we entered into an employment agreement with Mr. Brace outlining the terms of his employment (the "Brace Employment Agreement"). The material terms of the Brace Employment Agreement are outlined below. Except as noted otherwise below, capitalized terms used but not defined shall have the same meanings as described above with respect to the Employment Agreements.

        Pursuant to the Brace Employment Agreement, Mr. Brace will serve as our interim President and Chief Executive Officer for an initial term commencing on March 9, 2015 and ending on September 9, 2016, with automatic six-month term extensions following the expiration of the initial term or any subsequent six-month extension term, provided that neither party provides a notice of non-renewal at least 60 days prior to September 9, 2016 or the end of the applicable extension term. Under the Brace Employment Agreement, Mr. Brace will receive a monthly base salary of $100,000, which may be increased, but not decreased, at any time at the discretion of the Board of Directors. Mr. Brace is also eligible to receive an annual cash bonus and to participate in all other bonus, incentive, retirement and similar plans applicable generally to other similarly situated employees of us. Mr. Brace's target annual cash bonus is equal to 100 percent of his annual base salary, with the maximum annual cash bonus equal to 200 percent of his annual base salary and the minimum annual cash bonus equal to 50 percent of his annual base salary. Under the terms of the Brace Employment Agreement, Mr. Brace and/or his family, as the case may be, is also eligible to participate in other welfare benefit plans, in accordance with the terms and conditions of applicable policies as may be in effect and/or amended from time to time. Additionally, under the Brace Employment Agreement, Mr. Brace is eligible to receive other fringe benefits and limited perquisites appertaining to his position.

        Upon a termination of Mr. Brace's employment by us with Cause (as defined below), by Mr. Brace without Good Reason (as defined below), or due to death or disability during the term of the Brace Employment Agreement, Mr. Brace (or, in the case of death, Mr. Brace's legal representative) will be eligible to receive the Accrued Obligations and the Accrued Incentives.

        Upon a termination of Mr. Brace's employment by us without Cause or by Mr. Brace for Good Reason, in either case, during the term of the Brace Employment Agreement, Mr. Brace would receive the following: (i) the Accrued Obligations, (ii) the Accrued Incentives, (iii) a lump-sum cash payment equal to the greater of (x) the average of the annual cash bonuses paid to Mr. Brace for the period employed with us or (y) the target annual cash bonus (i.e., 100 percent of Mr. Brace's annual base salary), and (iv) the continued payment of Mr. Brace's base salary for the remainder of the term of the Brace Employment Agreement.

        For purposes of the Brace Employment Agreement, "Cause", in all material respects, means: (i) nonperformance by Mr. Brace of his obligations and duties that is not cured after written notice from the Board of Directors, (ii) commission by Mr. Brace of an act of fraud, embezzlement, misappropriation, willful misconduct or breach of fiduciary duty against us or other conduct harmful or potentially harmful to our best interest, (iii) a material breach by Mr. Brace of the non-competition, non-solicitation, or confidentiality obligations under the Brace Employment Agreement that is not

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cured after written notice from the Board of Directors, (iv) Mr. Brace's conviction, plea of no contest or nolo contendere, deferred adjudication or unadjudicated probation for any felony or any crime involving fraud, dishonesty, or moral turpitude or causing material harm, financial or otherwise, to us, (v) the refusal or failure of Mr. Brace to carry out, or comply with, in any material respect, any lawful directive of our Board of Directors that is not cured after written notice from the Board of Directors, (vi) Mr. Brace's unlawful use (including being under the influence) or possession of illegal drugs, or (vii) Mr. Brace's willful violation of any federal, state, or local law or regulation applicable to us or our business which adversely affects us that is not cured after written notice from the Board of Directors.

        For purposes of the Brace Employment Agreement, "Good Reason" means any of the following, but only if occurring without Mr. Brace's consent: (i) a material diminution in Mr. Brace's base salary or target annual cash bonus opportunity, (ii) a material diminution in Mr. Brace's authority, duties, or responsibilities, (iii) the relocation of Mr. Brace's principal office to an area more than 50 miles from its location immediately prior to such relocation, or (iv) our failure to comply with any material provision of the Brace Employment Agreement.

        Severance payments made under the Brace Employment Agreement are contingent upon Mr. Brace's execution of a valid release of claims. Further, severance payments may be stopped and any payments already made must be repaid in the event Mr. Brace violates the confidentiality, non-competition or non-solicitation provisions of the Brace Employment Agreement.

        In the event that Section 280G of the Code applies to any compensation payable to Mr. Brace, the Brace Employment Agreement provides that we will either (x) reduce the payment(s) to an amount that is one dollar less than the amount that would trigger the application of Section 280G of the Code, or (y) make the full payment owed to Mr. Brace, whichever of (x) or (y) results in the best net after tax position for Mr. Brace. The Brace Employment Agreement does not provide any obligation for us to pay a "gross-up" or make Mr. Brace whole for any excise or regular income taxes, including the excise taxes that may be due under Section 4999 of the Code.

Severance Arrangements

John A. Crum

        On March 20, 2014, we announced that Mr. Crum would resign from his position as President, Chief Executive Officer and Chairman of the Board, effective as of March 31, 2014. In connection with Mr. Crum's resignation, we entered into a separation agreement with Mr. Crum (the "Crum Separation Agreement").

        Pursuant to the Crum Separation Agreement, Mr. Crum was entitled to receive the following payments and benefits following his separation: (i) salary continuation payments for a period of 24 months following separation, in an aggregate amount of $1,200,000, the right to which arose from Mr. Crum's employment agreement; (ii) a lump sum cash payment of $320,000, or the average of the annual bonuses paid to Mr. Crum for the years in which he was employed by us, the right to which also arose from Mr. Crum's employment agreement; (iii) a lump sum cash payment of $540,000, or the amount to be paid to Mr. Crum under our annual cash bonus program for 2013; (iv) accelerated vesting of Mr. Crum's outstanding unvested restricted stock awards, or 150,000 shares of restricted stock and (v) the Accrued Obligations as defined in Mr. Crum's employment agreement.

        Under the Crum Separation Agreement, Mr. Crum has agreed to continue to abide by the confidentiality, non-competition and non-solicitation covenants in the employment agreement that we entered into with Mr. Crum to the extent applicable following his separation. As a condition to receipt of the consideration described in the preceding paragraph, Mr. Crum has agreed to execute a waiver and release of claims in favor of us.

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Thomas L. Mitchell

        Effective January 6, 2014, Mr. Mitchell resigned from employment with the Company and Mr. Haight was promoted to the position of Senior Vice President and Chief Financial Officer. We did not enter into a separation agreement with Mr. Mitchell in connection with his termination of employment.

Curtis Newstrom

        Effective July 3, 2014 Mr. Newstrom resigned from employment with the Company. We did not enter into a separation agreement with Mr. Newstrom in connection with his termination of employment.

Greg Hebertson

        On December 16, 2014 Gregory F. Hebertson entered into a separation agreement with us (the "Hebertson Separation Agreement"). Pursuant to the Hebertson Separation Agreement, Mr. Hebertson was entitled to receive the following payments and benefits following his separation: (i) salary continuation payments for a period of 12 months following separation, in an aggregate amount of $315,000, (ii) a lump sum cash payment of $116,000, which represents the average of the annual bonuses paid to Mr. Hebertson for the preceding three fiscal years, (iii) a lump sum cash payment of $187,360, which represents the accrued amount arising from Mr. Hebertson's participation in our annual bonus program, (iv) a lump sum payment in the amount of $63,000, which represents the unvested amount arising from Mr. Hebertson's loyalty and retention award, and (v) reimbursement for any COBRA expenses incurred in the first three months following Mr. Heberston's termination of employment.

        Under the Hebertson Separation Agreement, Mr. Hebertson has agreed to continue to abide by the confidentiality, non-competition and non-solicitation covenants in the employment agreement that we entered into with Mr. Hebertson to the extent applicable following his separation. As a condition to receipt of the consideration described in the preceding paragraph, Mr. Hebertson has agreed to execute a waiver and release of claims in favor of us.

Dexter Burleigh

        On December 19, 2014, Dexter Burleigh, who was serving as our Senior Vice President—Strategic Planning and Treasury, notified us of his intent to retire from his current position, effective January 1, 2015. In connection with Mr. Burleigh's retirement, Mr. Burleigh entered into an agreement (the "Burleigh Separation Agreement") with us pursuant to which Mr. Burleigh resigned as an officer, effective January 1, 2015. Following his execution of a waiver and release, Mr. Burleigh received (i) his target bonus for 2014 in the amount of $188,500, (ii) a lump sum severance payment of $456,761, representing 12 months of his annual base salary plus his average annual bonus for the prior three years, (iii) a lump sum payment of $29,000, which represents the unvested amount arising from Mr. Burleigh's loyalty and retention award, and (iv) reimbursement for any COBRA expenses incurred in the first three months following Mr. Burleigh's retirement. With respect to Mr. Burleigh's outstanding awards under the LTIP, the Burleigh Separation Agreement provides that so long as a release of claims is timely executed and not revoked, all 173,608 unvested shares of restricted common stock held by him at his retirement will vest as of the date of the Burleigh Separation Agreement. The Burleigh Separation Agreement contains non-competition, non-solicitation and non-disparagement provisions, provisions regarding reimbursement for continued health insurance coverage and a waiver and release. The non-competition and non-solicitation restrictions continue for one year following Mr. Burleigh's date of departure.

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Peter J. Hill

        On March 4, 2015, Dr. Peter J. Hill notified the Board of his intent to resign from his current position as interim President and Chief Executive Officer immediately following the filing of the Company's annual report on Form 10-K, which occurred on March 16, 2014. Furthermore, Dr. Hill resigned from the Board effective as of March 9, 2015. Dr. Hill was available to provide transition services to us until April 30, 2015. To date, we have not entered into a separation agreement with Dr. Hill in connection with his resignation or separation from service.

Accounting and Tax Considerations

        Under Section 162(m) of the Internal Revenue Code a limitation is placed on tax deductions of any publicly-held corporation for individual compensation to "covered employees" (within the meaning of Section 162(m) of the Internal Revenue Code) of such corporation exceeding $1,000,000 in any taxable year, unless the compensation meets certain requirements for qualified "performance-based compensation." Newly public companies generally are not subject to the deduction limitations of Section 162(m) of the Internal Revenue Code until the first stockholder meeting that occurs after the close of the third calendar year following the calendar year in which the initial public offering occurs, or at the time of a material amendment to the plan, whichever occurs first. We became subject to the limitations and requirements of Section 162(m) as of the 2014 Annual Meeting.

        Our policy is to have compensation programs that recognize and reward performance that increases stockholder value and, to the extent consistent with this policy, to seek to maintain the favorable tax treatment of that compensation. We believe, however, that under some circumstances, such as to attract or retain key executives or to recognize outstanding performance, it is in our best interest and in the best interest of our stockholders to provide compensation to selected executives even if it is not fully deductible.

        Section 280G of the Code prevents a corporate payor of certain types of payments made to executives in connection with a change of control from deducting portions of such payments from the corporation's gross income for federal income tax purposes, to the extent they exceed certain monetary thresholds (the excess over those thresholds is referred to as the "excess parachute payment"). In addition, Section 4999 of the Code imposes an excise tax on the recipient of these payments equal to 20% of the amount of the excess parachute payment. Some companies provide "gross-ups" to their executives to cover any excise tax that may become due under Section 4999 of the Code. The Employment Agreements do not provide any obligation for us to pay a "gross-up" or make the executive whole for any excise or regular income taxes, including any excise taxes that may be due under Section 4999 of the Code.

        All equity awards to our employees, including our Named Executive Officers, and to our directors will be granted and reflected in our consolidated financial statements, based upon the applicable accounting guidance, at fair market value on the grant date in accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), Topic 718, "Compensation—Stock Compensation."

Compensation Practices as They Relate to Risk Management

        We believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees). Our annual performance-based cash incentive program is based upon several different performance metrics that are both quantitative and qualitative, thus emphasizing well rounded company performance and growth rather than encouraging our executives to focus on achieving a single performance goal and the exclusion of others. Further, because our Compensation Committee retains the ability to apply discretion when determining the actual amount to be paid to executives pursuant to our annual performance-based cash incentive program, our Compensation

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Committee is able to assess the actual behavior of our executives as it relates to risk taking in awarding bonus amounts. Further, our use of long-term equity-based compensation serves our compensation program's goal of aligning the interests of executives and stockholders over the long-term, thereby reducing the incentives to take unnecessary short-term risk.

Compensation Committee Interlocks and Insider Participation

        During 2014, no member of the Compensation Committee served as an executive officer of the Company. During 2014, there were no Compensation Committee interlocks with other companies.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        The following table sets forth certain information regarding the beneficial ownership of Common Stock as of September 21, 2015, by (i) each person who is known by the Company to own beneficially more than five percent of the outstanding shares of Common Stock, (ii) each Named Executive Officer of the Company, (iii) each director and director nominee of the Company and (iv) all directors and executive officers as a group. Unless otherwise noted, the mailing address of each person or entity named below is 321 South Boston Avenue, Suite 1000, Tulsa, Oklahoma 74103.

        As of September 21, 2015, 7,153,872 shares of our Common Stock were outstanding.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Procedures for Review, Approval and Ratification of Related Person Transactions

        A "Related Party Transaction" is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A "Related Person" means:

•

any person who is, or at any time during the applicable period was, one of the Company's executive officers or one of its directors;



•

any person who is known by the Company to be the beneficial owner of more than 5% of the Company's Common Stock;



•

any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of the Company's Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of the Company's Common Stock; and



•

any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

        The Board of Directors has determined that the Audit Committee will periodically review all related person transactions that the rules of the SEC require be disclosed in the Company's proxy statement, and make a determination regarding the initial authorization or ratification of any such transaction.

        The Audit Committee is charged with reviewing the material facts of all related person transactions and either approving or disapproving of the Company's participation in such transactions under the Company's written Related Persons Transaction Policy adopted by the Board of Directors at the time of our initial public offering in April 2012, which pre-approves or ratifies (as applicable) certain related person transactions, including:

•

any employment of an executive officer if his or her compensation is required to be reported in the Company's proxy statement under Item 402;



•

director compensation that is required to be reported in the Company's proxy statement under Item 402;



•

any transaction with another company at which a Related Person's only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company's shares if the aggregate amount involved for any particular service does not exceed the greater of $500,000 or 25% of that company's total annual revenues; and



•

charitable contribution, grant or endowment by the Company to a charitable organization, foundation or university at which a Related Person's only relationship is as an employee (other than an executive officer) or a director if the aggregate amount involved does not exceed the lesser of $200,000 or 10% of the charitable organization's total annual receipts.

        In determining whether to approve or disapprove entry into a Related Party Transaction, the Audit Committee shall take into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person's interest in the

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transaction. Further, the policy requires that all Related Party Transactions required to be disclosed in the Company's filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations.

        There were no related persons transactions since January 1, 2014 which were required to be reported in "Certain Relations and Related Party Transactions," where the procedures described above did not require review, approval or ratification or where these procedures were not followed. In addition, since January 1, 2014, there has not been any transaction or series of similar transactions to which the Company was or is a party in which the amount involved exceeded or exceeds $120,000 and in which any of the Company's directors, executive officers, holders of more than 5% of any class of its voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in "Executive Compensation and Other Information," and the transactions described or referred to below.

Stockholders' Agreement

        In connection with the closing of our initial public offering, we entered into a stockholders' agreement (the "Stockholders' Agreement") with FRMI, Stephen J. McDaniel (former director and Chairman of the Board), and certain of our executive officers and other members of our management team. The Stockholders' Agreement contains several provisions relating to the sale of our Common Stock by the parties thereto, a summary of which is set forth below.

        The Stockholders' Agreement grants FRMI the right to nominate three members of our Board of Directors so long as FRMI holds at least 25% of our outstanding shares of Common Stock. Upon the identification by our Board of Directors of an additional director nominee that our Board of Directors has affirmatively determined is independent pursuant to the listing standards of the NYSE and Rule 10A-3 of the Exchange Act, FRMI has agreed to cause one of its director nominees to resign if so requested by the Board. In March 2013, the Board notified FRMI that it had identified Dr. Hill as an additional independent director and Mr. Krueger, an FRMI nominee, resigned from the Board, effective at the time of Dr. Hill's appointment in April 2013. At and as of such time that FRMI holds less than 25% of our outstanding shares of Common Stock, FRMI will have the right to nominate one member of our Board of Directors. The Stockholders' Agreement also requires the stockholders party thereto to take all necessary actions, including voting their shares of Common Stock, for the election of the FRMI nominees and the Board's other nominees.

Eagle Registration Rights Agreement

        On October 1, 2012, in connection with the closing of the Company's acquisition of the assets of Eagle Energy Production, LLC ("Eagle"), the Company, Eagle, FRMI and certain of our other stockholders entered into a Registration Rights Agreement (the "Eagle Registration Rights Agreement"), pursuant to which the Company has agreed to register the sale of shares of our Common Stock under the circumstances described below. The provisions relating to registration rights in the Eagle Registration Right Agreement supersede the provisions relating to registration rights contained in the Stockholders' Agreement that previously applied to FRMI only.

        At any time after the conversion of the Preferred Stock into Common Stock (with respect to Eagle) or October 25, 2012 (with respect to FRMI), Eagle or FRMI, as applicable, has the right to require us by written notice to register the sale of any number of their shares of Common Stock. We are required to provide notice of the demand request within 30 days following receipt of such demand request to all stockholders party to the Eagle Registration Rights Agreement to allow for inclusion of such other stockholders' Common Stock. Eagle and FRMI each have the right to cause up to an aggregate of six such demand registrations. In no event shall more than one demand registration occur

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within six months after the effective date of a registration statement filed pursuant to a demand request or within 60 days prior to our good faith estimate of the date of an offering and 180 days after the effective date of a registration statement we file.

        If, at any time, we propose to register an offering of Common Stock (subject to certain exceptions) for our own account, then we must give prompt notice (subject to reduction to one business day's notice in connection with certain offerings) to all stockholders party to the Eagle Registration Rights Agreement to allow them to include a specified number of their shares in that registration statement.

        These registration rights are subject to certain conditions and limitations, including the right of underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. The obligations to register shares under the Eagle Registration Rights Agreement will terminate when no registrable shares (as defined in the Eagle Registration Rights Agreement) remain outstanding.

Certain Rights of the Holders of Preferred Stock

        In connection with the Eagle Energy Acquisition, on September 28, 2012, the Company filed with the Secretary of State of the State of Delaware a Certificate of Designations (the "Certificate of Designations") to designate 325,000 shares of the Preferred Stock as Series A Mandatorily Convertible Preferred Stock.

        On September 30, 2015, all 325,000 shares of the Preferred Stock automatically converted into shares of Common Stock. Each share of Preferred Stock converted into approximately 11.5 shares of Common Stock pursuant to the Certificate of Designations, which governed the Preferred Stock. As a result, the Company issued 3,738,424 additional shares of Common Stock upon conversion of the Preferred Stock.

Transactions with Related Persons

        For the fiscal year ended 2014, Scott McDaniel, who is the brother of Stephen J. McDaniel (former director and Chairman of the Board), received $207,996 in total cash compensation as an employee of the Company. In addition, Scott McDaniel was eligible to participate in all benefit plans and programs available generally to the Company's employees, including his receipt of a grant of 19,200 shares of restricted stock under the LTIP. As of April 2014, Scott McDaniel was no longer an employee of the Company. In connection with his departure, all of his shares of restricted stock valued at approximately $151,567 vested in full.

Director Independence

        The Company's standards for determining director independence require the assessment of directors' independence each year. A director cannot be considered independent unless the Board of Directors affirmatively determines that he or she does not have any relationship with management or the Company that may interfere with the exercise of his or her independent judgment, including any of the relationships that would disqualify the director from being independent under the rules of the NYSE.

        The Board of Directors has assessed the independence of each non-employee director under the Company's guidelines and the independence standards of the NYSE. The Board of Directors affirmatively determined that Messrs. DeMontrond, Knudson, Mogford, Stover, Ogle and Carr are independent.

        In connection with its assessment of the independence of each non-employee director, the Board of Directors also determined that (i) Messrs. Stover, Ogle and Carr are independent, as defined in Section 10A of the Exchange Act and under the standards set forth by the NYSE applicable to members of the Audit Committee and (ii) Messrs. Stover, DeMontrond and Carr are independent under the standards set forth by the NYSE applicable to members of the Compensation Committee.

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

        At the closing of the offering of the old notes, we entered into a registration rights agreement with the initial purchaser pursuant to which we agreed, for the benefit of the holders of the old notes, at our cost, to do the following:

•

file an exchange offer registration statement with the SEC with respect to the exchange offer for the new notes, and



•

use commercially reasonable efforts to have the exchange offer completed no later than 270 days after May 21, 2015.

        Upon the SEC's declaring the exchange offer registration statement effective, we agreed to offer the new notes in exchange for surrender of the old notes. We agreed to use commercially reasonable efforts to cause the exchange offer registration statement to be effective continuously, and to keep the exchange offer open for a period of not less than 20 business days.

        For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the date of original issuance or, if interest has already been paid, from the last interest payment date on which interest was paid on the surrendered old note. The registration rights agreement also provides an agreement to include in the prospectus for the exchange offer certain information necessary to allow a broker dealer who holds old notes that were acquired for its own account as a result of market making activities or other trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker dealer in the exchange offer. We agreed to use commercially reasonable efforts to maintain the effectiveness of the exchange offer registration statement for these purposes for a period ending on the earlier of 180 days from the date on which the exchange offer registration statement is declared effective and the date on which the broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities.

        The preceding agreement is needed because any broker dealer who acquires old notes for its own account as a result of market making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the new notes pursuant to the exchange offer and the resale of new notes received in the exchange offer by any broker dealer who held old notes acquired for its own account as a result of market making activities or other trading activities, other than old notes acquired directly from us or one of our affiliates.

        Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer would in general be freely tradable after the exchange offer without further registration under the Securities Act. However, any purchaser of old notes who is an "affiliate" of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

•

will not be able to rely on the interpretation of the staff of the SEC,



•

will not be able to tender its old notes in the exchange offer, and



•

must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the old notes unless such sale or transfer is made pursuant to an exemption from such requirements.

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        Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the exchange offer will be required to make the representations described below under "—Procedures for Tendering—Your Representations to Us."

        We further agreed to file with the SEC a shelf registration statement to register for public resale old notes held by any holder who provides us with certain information for inclusion in the shelf registration statement if:

•

the exchange offer is not permitted by applicable law or SEC policy;



•

the exchange offer is for any reason not consummated within 270 days of May 21, 2015; or



•

any holder notifies us that:



•

the holder is prohibited by applicable law or SEC policy from participating in the exchange offer;



•

the holder may not resell the new notes acquired in the exchange offer to the public without delivering a prospectus, and the prospectus contained in the exchange offer registration statement is not appropriate or available for such resales by such holder; or



•

the holder is a broker-dealer and holds old notes acquired directly from us or one of our affiliates that are not freely tradable, and such holder cannot participate in the exchange offer.

        We have agreed to use commercially reasonable efforts to cause any shelf registration statement to be declared effective by the SEC (or automatically become effective under the Securities Act) on or before the 90th day after the date the shelf registration statement was filed. We refer to the date the shelf registration statement is required to be filed as the "shelf filing deadline." The shelf filing deadline is as soon as practicable, but in any event on or prior to 30 days after the date the obligation to file the shelf registration statement arises. We have also agreed to use commercially reasonable efforts to keep the shelf registration statement continuously effective for a period of one year following the effective date of the shelf registration statement (or for such shorter period that terminates when all the old notes covered by the shelf registration statement have been sold).

        The registration rights agreement provides that, in the event (i) the exchange offer is not consummated within 270 days of May 21, 2015, (ii) a shelf registration statement, if required, is not declared effective (or does not automatically become effective) on or prior to the 90th calendar day following any shelf filing deadline, or (iii) any required shelf registration statement ceases to remain effective or becomes unusable in connection with resale for more than 30 calendar days (each such event referred to in clauses (i) through (iii) above, a "Registration Default"), the interest rate on the old notes will be increased by 1.0% per annum, until the earlier of the completion of the exchange offer or until no Registration Default is in effect, at which time the increased interest shall cease to accrue and shall be reduced to the original interest rate of the old notes.

        Holders of the old notes will be required to make certain representations to us (as described under "—Procedures for Tendering—Your Representations to Us" and as set forth in Item 5 of the accompanying letter of transmittal) in order to participate in the exchange offer and will be required to deliver information to be used in connection with any shelf registration statement and to provide comments on any shelf registration statement within the time periods set forth in the registration rights agreement in order to have their old notes included in the shelf registration statement.

        If we effect the registered exchange offer, we will be entitled to close the registered exchange offer 20 business days after its commencement as long as we have accepted all old notes validly tendered in accordance with the terms of the exchange offer and no brokers or dealers continue to hold any old notes.

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        This summary of the material provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, a copy of which is filed as an exhibit to the registration statement that includes this prospectus.

        Except as set forth above, after consummation of the exchange offer, holders of old notes that are the subject of the exchange offer will have no registration or exchange rights under the registration rights agreement. Please read "—Consequences of Failure to Exchange."

Terms of the Exchange Offer

        Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to the expiration time of the exchange offer. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in denominations of $2,000 or integral multiples of $1,000 in excess thereof. We will deliver the new notes promptly after the expiration time of the exchange offer.

        The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered in the exchange offer.

        As of the date of this prospectus, $625.0 million in aggregate principal amount of the old notes is outstanding. This prospectus is being sent to DTC, the sole registered holder of the old notes, as of the date of this prospectus. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

        We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC. Old notes whose holders do not tender the old notes for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.

        We will be deemed to have accepted for exchange properly tendered old notes when we have given oral (promptly confirmed in writing) or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

        If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. Please read "—Fees and Expenses."

        We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holders promptly after the expiration or termination of the exchange offer, as applicable.

Expiration Time

        The exchange offer will expire at 5:00 p.m., New York City time, on November 16, 2015, unless, in our sole discretion, we extend it.

Extensions, Delays in Acceptance, Termination or Amendment

        We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving written notice of

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such extension to their holders at any time until the exchange offer expires or terminates. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

        To extend the exchange offer, we will notify the exchange agent orally (promptly confirmed in writing) or in writing of any extension. We will notify the holders of old notes of the extension via a press release issued no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration time.

        If any of the conditions described below under "—Conditions to the Exchange Offer" have not been satisfied, we reserve the right, in our sole discretion to:

•

extend the exchange offer;



•

delay accepting any old notes; or



•

terminate the exchange offer;

by giving oral (promptly confirmed in writing) or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

        Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by written notice thereof to holders of the old notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The prospectus supplement will be distributed to holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to holders, we will extend the exchange offer if it would otherwise expire during such period. If an amendment constitutes a material change to the exchange offer, including the waiver of a material condition, we will extend the exchange offer, if necessary, to remain open for at least five business days after the date of the amendment.

Conditions to the Exchange Offer

        We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

        We will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under "—Procedures for Tendering" and "Plan of Distribution" and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

        Additionally, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the exchange offer registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939.

        We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give written notice of any extension, amendment, non-acceptance or termination to the exchange agent and the holders of the old notes as promptly as practicable.

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        These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times prior to the expiration of the exchange offer in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times prior to the expiration of the exchange offer.

Procedures for Tendering

        To participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes, and you should follow carefully the instructions on how to tender your old notes. It is your responsibility to properly tender your old notes. We have the right to waive any defects. However, we are not required to waive defects, and neither we nor the exchange agent is required to notify you of any defects in your tender.

        If you have any questions or need help in exchanging your old notes, please call the exchange agent whose address and phone number are described in the letter of transmittal included as Annex A to this prospectus.

        All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates registered in the name of Cede & Co., the nominee of DTC. We have confirmed with DTC that the old notes may be tendered using ATOP. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer, and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an "agent's message" to the exchange agent. The agent's message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

        By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

        There is no procedure for guaranteed late delivery of the old notes.

        Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read "Plan of Distribution."

        Determinations Under the Exchange Offer.    We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that

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are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder promptly after the expiration time of the exchange offer.

        When We Will Issue New Notes.    In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent receives, prior to the expiration time of the exchange offer:

•

a book-entry confirmation of such old notes into the exchange agent's account at DTC; and



•

a properly transmitted agent's message.

        Return of Old Notes Not Accepted or Exchanged.    If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly upon the expiration or termination of the exchange offer, as applicable.

        Your Representations to Us.    By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

•

any new notes that you receive will be acquired in the ordinary course of your business;



•

you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes in violation of the provisions of the Securities Act;



•

you are not an "affiliate" (within the meaning of Rule 405 under the Securities Act); and



•

if you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making or other trading activities, then you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) in connection with any resale of the new notes.

Withdrawal of Tenders

        Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to the expiration time of the exchange offer. For a withdrawal to be effective, you must comply with the appropriate ATOP procedures. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the ATOP procedures.

        We will determine all questions as to the validity, form, eligibility and time of receipt of a notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

        Any old notes that have been tendered for exchange but that are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender, expiration or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under "—Procedures for Tendering" above at any time prior to the expiration time of the exchange offer.

Fees and Expenses

        We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by telephone or in person by our officers and regular employees and those of our affiliates.

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        We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

        We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

•

SEC registration and filing fees;



•

fees and expenses of the exchange agent and trustee;



•

accounting and legal fees and printing costs; and



•

related fees and expenses.

Transfer Taxes

        We will pay all transfer taxes, if any, applicable to the exchange of old notes in the exchange offer. Each tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes in the exchange offer.

Consequences of Failure to Exchange

        If you do not exchange your old notes for new notes in the exchange offer, the old notes you hold will remain outstanding and continue to accrue interest, but will continue to be subject to the existing restrictions on transfer. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not intend to register the old notes under the Securities Act unless the registration rights agreement requires us to do so.

Accounting Treatment

        We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes to be accrued over the life of the notes, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer, other than the recognition of the fees and expenses of the offering as stated under "—Fees and Expenses."

Other

        Participation in the exchange offer is voluntary, and you should consider carefully whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

        We may in the future seek to acquire untendered old notes in the open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

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RATIO OF EARNINGS TO FIXED CHARGES

        The table below sets forth our ratio of earnings to fixed charges for the periods indicated on a consolidated historical basis. The computation of earnings to fixed charges is set forth on exhibit 12.1 to the registration statement of which this prospectus forms a part.

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DESCRIPTION OF NEW NOTES

        You can find the definitions of certain terms used in this description under the subheading "—Certain Definitions." In this description, the terms "we," "our" and "us" refer to Midstates Petroleum Company, Inc. and its consolidated Subsidiaries, the term "Company" refers only to Midstates Petroleum Company, Inc. and not to any of its Subsidiaries, the term "Co-Issuer" refers only to Midstates Petroleum Company LLC and the term "Issuers" refers to both the Company and the Co-Issuer. References to the "notes" in this section of the prospectus include both the old notes issued on May 21, 2015 and the new notes, unless the context otherwise requires.

        The new notes will be issued, and the old notes were issued, under an indenture, dated as of May 21, 2015 among the Issuers and Wilmington Trust, National Association, as trustee and collateral agent. The terms of the notes will include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended.

        The following description is a summary of the material provisions of the indenture, the notes, the Intercreditor Agreement and the Note Documents. It does not restate those agreements in their entirety. We urge you to read the relevant agreements because they, and not this description, define your rights as holders of the notes. A copy of the indenture the notes, the Intercreditor Agreement and the Note Documents are filed as exhibits to the registration statement of which this prospectus forms a part. Certain defined terms used in this description but not defined below under "—Certain Definitions" have the meanings assigned to them in the indenture. The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders have rights under the indenture.

        If the exchange offer is consummated, holders of the old notes who do not exchange their notes for new notes will vote together with the holders of the new notes for all relevant purposes under the indenture. In that regard, the indenture requires that certain actions by the holders under the indenture (including acceleration after an Event of Default) must be taken, and certain rights must be exercised by specified minimum percentages of the aggregate principal amount of all notes issued under the indenture. In determining whether holders of the requisite percentage in principal amount have given any notice, consent or waiver or taken any other action permitted under the indenture, any old notes that remain outstanding after the exchange offer will be aggregated with the new notes, and the holders of any old notes and the new notes will vote together as a single series for all such purposes. Accordingly, all references in this "Description of New Notes" to specified percentages in aggregate principal amount of the outstanding notes mean, at any time after the exchange offer for the old notes is consummated, such percentage in aggregate principal amount of such old notes and the new notes outstanding.

Brief Description of the Notes and the Note Guarantees

The Notes

        Like the old notes, the new notes will be:

•

senior obligations of the Issuers;



•

issued in an aggregate principal amount of $625 million;



•

effectively junior, pursuant to the terms of the Intercreditor Agreement, to the Issuers' and any Guarantors' obligations under the Credit Agreement, to the extent of the value of the collateral securing such Indebtedness, which are secured on a first-priority basis by liens on the Collateral;



•

effectively senior to all existing and future unsecured Indebtedness of the Issuers, including the Issuers' Existing Notes, to the extent of the value of the Collateral;

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•

effectively senior to all Junior Lien Obligations of the Issuers, to the extent of the value of the Collateral;



•

effectively junior to all existing and future secured Indebtedness of the Issuers or any of the Company's future Subsidiaries that is secured by Liens on assets other than Collateral, to the extent of the value of such assets;



•

equal in right of payment to all existing and future senior Indebtedness of the Issuers, including the Issuers' Existing Notes;



•

structurally subordinated to the Indebtedness and other liabilities of future Subsidiaries of the Company (other than the Co-Issuer) that do not guarantee the notes; and



•

senior in right of payment to all future subordinated Indebtedness of the Issuers.

The Note Guarantees

        The new notes, like the old notes, may be guaranteed by certain of the Company's future Restricted Subsidiaries (other than the Co-Issuer).

        Each guarantee of the new notes will be:

•

a senior obligation of that Guarantor;



•

secured on a second-priority basis, subject to the terms of the Intercreditor Agreement, by a Lien on the Collateral owned or held by that Guarantor;



•

equal in right of payment to all existing and future senior Indebtedness of that Guarantor;



•

effectively junior, pursuant to the terms of the Intercreditor Agreement, to the extent of the value of the Collateral, to that Guarantor's guarantee of the Issuers' obligations under the Credit Agreement and any other Priority Lien Obligations, which are secured on a first-priority basis by Liens on the Collateral;



•

effectively senior to all existing and future unsecured senior Indebtedness of that Guarantor, including any Guarantee of the Issuers' Existing Notes, to the extent of the value of the Collateral;



•

effectively senior to all Junior Lien Obligations of that Guarantor, to the extent of the value of the Collateral;



•

effectively junior to all existing and future secured Indebtedness of that Guarantor that is secured by Liens on assets other than Collateral, to the extent of the value of such assets; and



•

senior in right of payment to all future subordinated Indebtedness of that Guarantor.

        Our current sole Subsidiary, Midstates Petroleum Company LLC, is a Co-Issuer of the notes. Under the circumstances described below under the caption "—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries," we are permitted to designate certain of our Subsidiaries as Unrestricted Subsidiaries. Our Unrestricted Subsidiaries are not subject to the restrictive covenants in the indenture. Our Unrestricted Subsidiaries do not guarantee the notes, and if we designate any Restricted Subsidiary as an Unrestricted Subsidiary in accordance with the indenture, the Guarantee of such Subsidiary will be released.

Principal, Maturity and Interest

        The Issuers have issued $625 million in aggregate principal amount of the old notes. The Issuers have issued notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on the earlier of (a) twelve months after the maturity of the Credit Agreement, or

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any Credit Facility incurred to refinance or otherwise replace the Credit Agreement, or (b) June 1, 2020.

        Interest on the notes accrues at the rate of 10.0% per annum and is payable semi-annually in arrears on June 1 and December 1, commencing on December 1, 2015. The Issuers will make each interest payment to the holders of record on the immediately preceding May 15 and November 15.

        Interest on the new notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

        If a holder of notes has given wire transfer instructions to the Issuers, the Issuers will pay all principal, interest and premium, if any, on that holder's notes in accordance with those instructions. All other payments on the notes will be made at the office or agency of the paying agent and registrar unless the Issuers elect to make interest payments by check mailed to the holders of the notes at their address set forth in the register of holders.

Paying Agent and Registrar for the Notes

        The trustee will initially act as paying agent and registrar. The Issuers may change the paying agent or registrar without prior notice to the holders of the notes, and the Company or any of the Company's Subsidiaries may act as paying agent or registrar.

Transfer and Exchange

        A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. The Issuers will not be required to transfer or exchange any note selected for redemption. Also, the Issuers will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

Note Guarantees

        Our current sole Subsidiary, Midstates Petroleum Company LLC, is a Co-Issuer of the notes. The notes will be unconditionally guaranteed by any future Restricted Subsidiary of the Company (other than the Co-Issuer or any Immaterial Subsidiary that is not a Guarantor under any Credit Facility or any other Indebtedness) that (a) guarantees any Indebtedness of the Company or any Guarantor under any Credit Facility or (b) if there is no Credit Facility outstanding and in effect at such time, Indebtedness of the Company or any Restricted Subsidiary, subject to certain exceptions described under "Certain Covenants—Additional Note Guarantees." These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law.

        Except in a transaction in which its Note Guarantee will be released as provided below, a Guarantor may not sell or otherwise dispose of all or substantially all of its assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than an Issuer or another Guarantor, unless:

(1)

immediately after giving effect to that transaction, no Default or Event of Default exists; and

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(2)

either: (a) such Guarantor is the surviving Person or the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger assumes all the Obligations of that Guarantor under the indenture, the Note Documents and its Note Guarantee pursuant to a supplemental indenture or (b) the Net Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of the indenture;



(3)

the Person formed by or surviving any such consolidation or merger, if applicable, shall take such action (or agree to take such action) as may be reasonably necessary to cause any property or assets that constitute Collateral owned by or transferred to the Person formed by or surviving any such consolidation or merger to be subject to the Parity Liens in the manner and to the extent required under the Note Documents; and



(4)

the Company shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indentures and/or amendments or joinders with respect to the Note Security Documents (if any) comply with the indenture and constitute the legal, valid and binding obligations of such Guarantor.

        The Note Guarantee of a Guarantor will be released:

(1)

in connection with any sale, disposition or transfer of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the sale, disposition or transfer does not violate the "Asset Sale" provisions of the indenture;



(2)

in connection with any sale, disposition or transfer of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary such that the Guarantor is no longer a Restricted Subsidiary, if the sale, disposition or transfer does not violate the "Asset Sale" provisions of the indenture;



(3)

if the Company designates such Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture; or



(4)

upon legal defeasance or satisfaction and discharge of the indenture as provided below under the captions "—Legal Defeasance and Covenant Defeasance" and "—Satisfaction and Discharge".



(5)

unless a Default or Event of Default has occurred and is continuing, at such time as such Guarantor ceases to guarantee any Indebtedness of the Issuers or any other Restricted Subsidiary and is not otherwise obligated, under any Credit Facility.

Security for the Notes

        The Obligations of the Issuers with respect to the notes, the obligations of any Guarantors under the Note Guarantees, all other Parity Lien Obligations, and the performance of all other Obligations of the Issuers and any Guarantors under the Note Documents are secured by second-priority Liens on the Collateral granted to the Note Collateral Agent for the benefit of the holders of the Parity Lien Obligations. For all purposes of this Description of New Notes and the indenture, all references to "second-priority" Liens means Liens that may be junior in priority to the Liens securing Priority Lien Obligations, to the extent permitted to be incurred or to exist under the Intercreditor Agreement, and to Permitted Liens. These Liens are also senior in priority to the Liens securing Junior Lien Obligations, to the permitted to be incurred or to exist under the Note Documents.

        The indenture provides that the Collateral consists of the Issuers' and any Guarantors' Oil and Gas Properties and substantially all other assets of the Issuers and any Guarantors; provided that the indenture requires the Issuers to deliver to the Notes Collateral Agent semi-annually on or before

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November 1 and May 1 in each calendar year, beginning November 1, 2015, an officers' certificate certifying that, as of the date of such certificate, the Collateral includes proven Oil and Gas Properties constituting not less than 95% of the total discounted present value of Proved Reserves attributable to the Oil and Gas Properties of the Company and its Restricted Subsidiaries, as evaluated in the most recent Reserve Report, after giving effect to exploration and production activities, acquisitions, dispositions and production since the date of such Reserve Report.

        The Collateral does not include any Priority Lien Collateral that is or may be provided as cash collateral to certain issuers of letters of credit pursuant to the Priority Lien Documents rather than generally to the holders of Priority Lien Obligations or to Priority Lien Collateral Agent for the benefit of the holders of the Priority Lien Obligations as a whole.

        Certain security interests or liens in the Collateral may not have been in place on the date of the indenture or may not have been perfected on the date of the indenture. The indenture provides for a (i) 60-day period following the Issue Date for the Issuers to deliver and record the Mortgages establishing the Parity Liens on the Collateral for the notes, (ii) a 60-day period following the Issue Date for the Issuers to deliver or cause to be delivered control agreements with respect to certain deposit accounts and securities accounts maintained by either Issuer or any Guarantor (or as such period may be extended by the Credit Facility Agent but in no event later than 90 days following the initial issuance of the notes) and (iii) a 60 day period following the Issue Date for the Issuers to deliver a customary collateral perfection certificate. In addition, the Note Security Documents did not require that security interests be perfected on the Issue Date if such security interests could not be perfected by the filing of UCC financing statements. See "Risk Factors—Security over certain collateral on which a lien in favor of the Note Collateral Agent is required may not have been perfected on the Issue Date."

        The Note Security Documents and Mortgages providing for the Parity Liens are or will be substantially in the form of the corresponding instruments providing for the Priority Liens, with such changes as are reasonably necessary to reflect the terms of the Intercreditor Agreement and with such deletions or modifications of representations, warranties and covenants as are customary with respect to security documents establishing Liens securing publicly traded debt securities.

The Intercreditor Agreement

        The Note Collateral Agent, the Priority Lien Collateral Agent and the Junior Lien Collateral Agent are parties to the Intercreditor Agreement, which provides for, among other things, the junior nature of the Parity Liens with respect to Priority Liens and the senior nature of the Parity Liens with respect to Junior Liens. Although the holders of the notes are not parties to the Intercreditor Agreement, by their acceptance of the notes they agreed to be bound thereby. The Intercreditor Agreement permits the Priority Lien Obligations, the Parity Lien Obligations and the Junior Lien Obligations to be refunded, refinanced or replaced by certain permitted refinancing indebtedness without affecting the lien priorities set forth in the Intercreditor Agreement, in each case without the consent of any holder of Priority Lien Obligations, Parity Lien Obligations or Junior Lien Obligations (including holders of the notes).

Lien Priorities

        The Intercreditor Agreement provides that, notwithstanding:

(1)

anything to the contrary contained in the Note Security Documents establishing the Parity Liens, any documents establishing Priority Liens or any documents establishing Junior Liens;



(2)

how a Lien was acquired (whether by grant, possession, statute, operation of law, subrogation, or otherwise);

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(3)

the time, manner, order of the grant attachment or perfection of a Lien;



(4)

any conflicting provision of the New York Uniform Commercial Code or other applicable law;



(5)

any defect in, or non-perfection, setting aside, or avoidance of, a Lien or a Priority Lien Document, a Parity Lien Document or a Junior Lien Document;



(6)

the modification of a Priority Lien Obligation, a Parity Lien Obligation or a Junior Lien Obligation;



(7)

the subordination of a Lien on Collateral securing a Priority Lien Obligation to a Lien securing another obligation of the Issuers or other Person that is permitted under the Priority Lien Documents as in effect on the date hereof or securing a DIP Financing or the subordination of a Lien on Collateral securing a Parity Lien Obligation to a Lien securing another obligation of the Issuers or other Persons (other than a Priority Lien Obligation) that is permitted under the Parity Lien Documents as in effect on the Issue Date; or



(8)

all Parity Liens at any time granted by the Issuers or any Guarantor are or will be subject and subordinate to all Priority Liens securing Priority Lien Obligations, subject to the Priority Lien Cap, and senior to all Junior Liens securing Junior Lien Obligations, and all Junior Liens at any time granted by the Issuers or any Guarantor are or will be subject and subordinate to all Priority Liens securing Priority Lien Obligations, subject to the Priority Lien Cap, and all Parity Liens securing Parity Lien Obligations.

        The provisions described under the caption "—Lien Priorities" are intended for the benefit of, and are or will be enforceable as a third party beneficiary by, each present and future holder of Priority Lien Obligations, each present and future Priority Lien Collateral Agent as holder of Priority Liens, each present and future holder of Parity Lien Obligations and each present and future Note Collateral Agent as holder of Parity Liens. No other Person is entitled to rely on, have the benefit of or enforce those provisions.

        In addition, the provisions under the caption "—Lien Priorities" are intended solely to set forth the relative ranking, as Liens, of the Liens securing Parity Lien Debt as against the Priority Liens and Junior Liens, and the Liens securing Priority Lien Debt as against the Parity Liens and Junior Liens. Neither the notes nor any other Parity Lien Obligations are intended to be, or will ever be by reason of the foregoing provision, in any respect subordinated, deferred, postponed, restricted or prejudiced in right of payment.

Limitation on Enforcement of Remedies

        The Intercreditor Agreement provides that, except as provided below, prior to the Discharge of Priority Lien Obligations, none of the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent, or any holder of Junior Lien Obligations may commence any judicial or nonjudicial foreclosure proceedings with respect to, seek to have a trustee, receiver, liquidator or similar official appointed for or over, attempt any action to take possession of, exercise any right, remedy or power with respect to, or otherwise take any action to enforce its interest in or realize upon, or take any other action available to it in respect of, the Collateral under any Parity Lien Document or Junior Lien Document, as applicable, applicable law or otherwise (including but not limited to right of set off). Only the Priority Lien Collateral Agent is entitled to take any such actions or exercise any such remedies with respect to the Collateral prior to the Discharge of Priority Lien Obligations. The Intercreditor Agreement provides that, notwithstanding the foregoing, the Note Collateral Agent may, but will have no obligation to, on behalf of the holders of Parity Lien Obligations, and the Junior Lien Collateral Agent may, but will have no obligation to, on behalf of the holders of Junior Lien Obligations take all such actions (not adverse to the Priority Liens or the rights of the Priority Lien Collateral Agent and holders of the Priority Lien Obligations) it deems necessary to perfect or continue

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the perfection of their Parity Liens in the Collateral or to create, preserve or protect (but not enforce) the Parity Liens in the Collateral or to perfect or continue the perfection of the Junior Liens in the Collateral or to create, preserve or protect (but not enforce) the Junior Liens in the Collateral, as applicable. Nothing shall limit the right or ability of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent or the holders of Junior Lien Obligations to (i) purchase (by credit bid or otherwise) all or any portion of the Collateral in connection with any enforcement of remedies by the Priority Lien Collateral Agent so long as, the Priority Lien Collateral Agent and the holders of the Priority Lien Obligations receive payment in full in cash of all Priority Lien Obligations after giving effect thereto or (ii) file a proof of claim with respect to the Parity Lien Obligations or the Junior Lien Obligations, as applicable. Until the Discharge of Priority Lien Obligations, the Priority Lien Collateral Agent will have the exclusive right to deal with that portion of the Collateral consisting of deposit accounts and securities accounts, including exercising rights under control agreements with respect to such accounts. In addition, whether before or after the Discharge of Priority Lien Obligations, the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations may take any actions and exercise any and all rights that would be available to a holder of unsecured claims; provided, however, that the Note Collateral Agent, such holders of Parity Lien Obligations, the Junior Lien Collateral Agent and such holders of Junior Lien Obligations may not take any of the actions described below under clauses (1) through (9) of the first paragraph and clauses (1) through (9) of the second paragraph under the caption "—No Interference; Payment Over," as applicable, or prohibited by the provisions described in the first four paragraphs below under the caption "—Agreements With Respect to Insolvency or Liquidation Proceedings," as applicable; provided further that in the event that the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations becomes a judgment lien creditor in respect of any Collateral as a result of its enforcement of its rights as an unsecured creditor with respect to the Parity Lien Obligations or the Junior Lien Obligations, as applicable, such judgment lien shall be subject to the terms of the Intercreditor Agreement for all purposes (including in relation to the Priority Lien Obligations and the Parity Lien Obligations, as applicable), as the other liens securing the Parity Lien Obligations and the Junior Lien Obligations, are subject to the Intercreditor Agreement.

        The Intercreditor Agreement provides that, except as provided below, following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, neither the Junior Lien Collateral Agent nor any holder of Junior Lien Obligations may commence any judicial or nonjudicial foreclosure proceedings with respect to, seek to have a trustee, receiver, liquidator or similar official appointed for or over, attempt any action to take possession of, exercise any right, remedy or power with respect to, or otherwise take any action to enforce its interest in or realize upon, or take any other action available to it in respect of, the Collateral under any Junior Lien Document, applicable law or otherwise. Only the Note Collateral Agent is entitled to take any such actions or exercise any such remedies with respect to the Collateral following the Discharge of Priority Lien Obligations. The Intercreditor Agreement provides that, notwithstanding the foregoing, the Junior Lien Collateral Agent may, but will have no obligation to, on behalf of the holders of Junior Lien Obligations, take all such actions (not adverse to the Parity Liens or the rights of the Note Collateral Agent and holders of the Parity Lien Obligations) it deems necessary to perfect or continue the perfection of their Junior Liens in the Collateral or to create, preserve or protect (but not enforce) the Junior Liens in the Collateral. Following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, the Note Collateral Agent will have the exclusive right to deal with that portion of the Collateral consisting of deposit accounts and securities accounts, including exercising rights under control agreements with respect to such accounts.

        Notwithstanding the foregoing, prior to the Discharge of Priority Lien Obligations, both before and during an Insolvency or Liquidation Proceeding, after a period of 180 days has elapsed (which period will be tolled during any period in which the Priority Lien Collateral Agent is not entitled, on behalf of

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holders of Priority Lien Obligations, to enforce or exercise any rights or remedies with respect to any Collateral as a result of (x) any injunction issued by a court of competent jurisdiction or (y) the automatic stay or any other stay in any Insolvency or Liquidation Proceeding) since the date on which the Note Collateral Agent has delivered to the Priority Lien Collateral Agent written notice of the acceleration of the Parity Lien Debt (the "Parity Lien Standstill Period"), the Note Collateral Agent and the holders of Parity Lien Obligations may enforce or exercise any rights or remedies with respect to any Collateral; provided, however, that notwithstanding the expiration of the Parity Lien Standstill Period, in no event may the Note Collateral Agent or any other holder of Parity Lien Obligations enforce or exercise any rights or remedies with respect to any Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding, if the Priority Lien Collateral Agent on behalf of the holders of Priority Lien Obligations or any other holder of Priority Lien Obligations shall have commenced, and shall be diligently pursuing (or shall have sought or requested relief from, or modification of, the automatic stay or any other stay or prohibition in any Insolvency or Liquidation Proceeding to enable the commencement and pursuit thereof), the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding (prompt written notice thereof to be given to the Note Collateral Agent by the Priority Lien Collateral Agent); provided further that, at any time after the expiration of the Parity Lien Standstill Period, if neither the Priority Lien Collateral Agent nor any holder of Priority Lien Obligations shall have commenced and be diligently pursuing (or shall have sought or requested relief from, or modification of, the automatic stay or any other stay or other prohibition in any Insolvency or Liquidation Proceeding to enable the commencement and pursuit thereof) the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, and the Note Collateral Agent shall have commenced the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, then for so long as the Note Collateral Agent is diligently pursuing such rights or remedies, none of any holder of Priority Lien Obligations, the Priority Lien Collateral Agent, any holder of Junior Lien Obligations nor the Junior Lien Collateral Agent shall take any action of a similar nature with respect to such Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding.

        Notwithstanding the foregoing, prior to the Discharge of Priority Lien Obligations, both before and during an Insolvency or Liquidation Proceeding, after a period of 270 days has elapsed (which period will be tolled during any period in which the Priority Lien Collateral Agent is not entitled, on behalf of holders of Priority Lien Obligations, to enforce or exercise any rights or remedies with respect to any Collateral as a result of (x) any injunction issued by a court of competent jurisdiction or (y) the automatic stay or any other stay in any Insolvency or Liquidation Proceeding) since the date on which the Junior Lien Collateral Agent has delivered to the Priority Lien Collateral Agent written notice of the acceleration of any Junior Lien Debt (the "Junior Lien First Standstill Period"), the Junior Lien Collateral Agent and the holders of Junior Lien Obligations may enforce or exercise any rights or remedies with respect to any Collateral; provided, however, that notwithstanding the expiration of the Junior Lien First Standstill Period or anything in the collateral trust agreement governing the Junior Liens to the contrary, in no event may the Junior Lien Collateral Agent or any other holder of Junior Lien Obligations enforce or exercise any rights or remedies with respect to any Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding, if the Priority Lien Collateral Agent on behalf of the holders of Priority Lien Obligations, any other holder of Priority Lien Obligations, the Note Collateral Agent on behalf of the holders of Parity Lien Obligations or any other holder of Parity Lien Obligations shall have commenced, and shall be diligently pursuing (or shall have sought or requested relief from, or modification of, the automatic stay or any other stay or prohibition in any Insolvency or Liquidation Proceeding to enable the commencement and pursuit thereof), the enforcement or exercise

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of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding (prompt written notice thereof to be given to the Junior Lien Representatives by the Priority Lien Collateral Agent or the Note Collateral Agent, as applicable); provided, further, that, at any time after the expiration of the Junior Lien First Standstill Period, if none of the Priority Lien Collateral Agent, any holder of Priority Lien Obligations, the Note Collateral Agent or any holder of Parity Lien Obligations shall have commenced and be diligently pursuing the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, and the Junior Lien Collateral Agent shall have commenced the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, then for so long as the Junior Lien Collateral Agent is diligently pursuing such rights or remedies, none of any holder of Priority Lien Obligations, the Priority Lien Collateral Agent, any holder of Parity Lien Obligations or the Note Collateral Agent shall take any action of a similar nature with respect to such Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding.

        Notwithstanding the foregoing, following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, both before and during an Insolvency or Liquidation Proceeding, after a period of 180 days has elapsed (which period will be tolled during any period in which the Note Collateral Agent is not entitled, on behalf of holders of Parity Lien Obligations, to enforce or exercise any rights or remedies with respect to any Collateral as a result of (x) any injunction issued by a court of competent jurisdiction or (y) the automatic stay or any other stay in any Insolvency or Liquidation Proceeding) since the date on which the Junior Lien Collateral Agent has delivered to the Note Collateral Agent written notice of the acceleration of any Junior Lien Debt (the "Junior Lien Second Standstill Period"), the Junior Lien Collateral Agent and the holders of Junior Lien Obligations may enforce or exercise any rights or remedies with respect to any Collateral; provided, however, that notwithstanding the expiration of the Junior Lien Second Standstill Period or anything in the collateral trust agreement governing the Junior Liens to the contrary, in no event may the Junior Lien Collateral Agent or any other holder of Junior Lien Obligations enforce or exercise any rights or remedies with respect to any Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding, if the Note Collateral Agent on behalf of the holders of Parity Lien Obligations or any other holder of Parity Lien Obligations shall have commenced, and shall be diligently pursuing (or shall have sought or requested relief from, or modification of, the automatic stay or any other stay or prohibition in any Insolvency or Liquidation Proceeding to enable the commencement and pursuit thereof), the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding (prompt written notice thereof to be given to the Junior Lien Representatives by the Note Collateral Agent); provided further that, at any time after the expiration of the Junior Lien Second Standstill Period, if neither the Note Collateral Agent nor any holder of Parity Lien Obligations shall have commenced and be diligently pursuing the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, and the Junior Lien Collateral Agent shall have commenced the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding, then for so long as the Junior Lien Collateral Agent is diligently pursuing such rights or remedies, neither any holder of Parity Lien Obligations nor the Note Collateral Agent shall take any action of a similar nature with respect to such Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding.

Priority Lien Collateral Agent

        The Intercreditor Agreement provides that neither the Priority Lien Collateral Agent nor any holder of any Priority Lien Obligations has any duties or other obligations to any holder of Parity Lien

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Obligations or holder of Junior Lien Obligations with respect to the Collateral, other than to transfer to the Note Collateral Agent any remaining Collateral and the proceeds of the sale or other disposition of any Collateral remaining in its possession following the Discharge of Priority Lien Obligations, in each case, without representation or warranty on the part of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations.

        In addition, the Intercreditor Agreement further provides that, until the Discharge of Priority Lien Obligations (but subject to the rights of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations and the following expiration of any of the Parity Lien Standstill Period, the Junior Lien First Standstill Period or Junior Lien Second Standstill Period, as applicable, as provided in the paragraphs defining "Parity Lien Standstill Period," "Junior Lien First Standstill Period," and "Junior Lien Second Standstill Period"), the Priority Lien Collateral Agent is entitled, for the benefit of the holders of the Priority Lien Obligations, to sell, transfer or otherwise dispose of or deal with the Collateral without regard to (i) any Parity Lien therein granted to the holders of Parity Lien Obligations or any rights to which the Note Collateral Agent or any holder of Parity Lien Obligations would otherwise be entitled as a result of such Parity Lien or (ii) any Junior Lien granted therein to the holders of Junior Lien Obligations or any rights to which the Junior Lien Collateral Agent or any holder of Junior Lien Obligations would otherwise be entitled as a result of such Junior Lien. Without limiting the foregoing, the Intercreditor Agreement provides that neither the Priority Lien Collateral Agent nor any holder of any Priority Lien Obligations has any duty or obligation first to marshal or realize upon the Collateral, or to sell, dispose of or otherwise liquidate all or any portion of the Collateral, in any manner that would maximize the return to the holders of Parity Lien Obligations or the holders of the Junior Lien Obligations, notwithstanding that the order and timing of any such realization, sale, disposition or liquidation may affect the amount of proceeds actually received by the holders of Parity Lien Obligations or the holders of the Junior Lien Obligations, as applicable, from such realization, sale, disposition or liquidation.

        The Intercreditor Agreement additionally provides that the Note Collateral Agent, each holder of Parity Lien Obligations, the Junior Lien Collateral Agent and each holder of Junior Lien Obligations waives any claim that may be had against the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations arising out of any actions which the Priority Lien Collateral Agent or such holder of Priority Lien Obligations takes or omits to take (including actions with respect to the creation, perfection or continuation of Liens on any Collateral, actions with respect to the foreclosure upon, sale, release or depreciation of, or failure to realize upon, any Collateral, and actions with respect to the collection of any claim for all or any part of the Priority Lien Obligations from any account debtor, guarantor or any other party) in accordance with the Intercreditor Agreement and the Priority Lien Documents or the valuation, use, protection or release of any security for such Priority Lien Obligations.

Note Collateral Agent

        The Intercreditor Agreement provides that neither the Note Collateral Agent nor any holder of any Parity Lien Obligations has any duties or other obligations to any holder of Junior Lien Obligations with respect to the Collateral, other than to transfer to the Junior Lien Collateral Agent any remaining Collateral and the proceeds of the sale or other disposition of any Collateral remaining in its possession following the Discharge of Parity Lien Obligations (provided that such Discharge of Parity Lien Obligations occurs after the Discharge of Priority Lien Obligations), in each case, without representation or warranty on the part of the Note Collateral Agent or any holder of Parity Lien Obligations.

        In addition, the Intercreditor Agreement further provides that, after the Discharge of Priority Lien Obligations and until the Discharge of Parity Lien Obligations (but subject to the rights of the Junior Lien Collateral Agent and the holders of Junior Lien Obligations following the expiration of the Junior

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Lien Second Standstill Period, as provided in the paragraphs defining "Junior Lien Second Standstill Period"), the Note Collateral Agent is entitled, for the benefit of the holders of the Parity Lien Obligations, to sell, transfer or otherwise dispose of or deal with the Collateral without regard to any Junior Lien granted therein to the holders of Junior Lien Obligations or any rights to which the Junior Lien Collateral Agent or any holder of Junior Lien Obligations would otherwise be entitled as a result of such Junior Lien. Without limiting the foregoing, the Intercreditor Agreement provides that neither the Note Collateral Agent nor any holder of any Parity Lien Obligations has any duty or obligation first to marshal or realize upon the Collateral, or to sell, dispose of or otherwise liquidate all or any portion of the Collateral, in any manner that would maximize the return to the holders of Junior Lien Obligations, notwithstanding that the order and timing of any such realization, sale, disposition or liquidation may affect the amount of proceeds actually received by the holders of the Junior Lien Obligations, as applicable, from such realization, sale, disposition or liquidation. Following the Discharge of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations may, subject to any other agreements binding on the Junior Lien Collateral Agent and the holders of Junior Lien Obligations, assert their rights, under the New York Uniform Commercial Code or otherwise, to any proceeds remaining following a sale, disposition or other liquidation of Collateral by, or on behalf of, the holders of Junior Lien Obligations.

        The Intercreditor Agreement additionally provides that the Junior Lien Collateral Agent and each holder of Junior Lien Obligations waives any claim that may be had against the Note Collateral Agent or any holder of any Parity Lien Obligations arising out of any actions which the Note Collateral Agent or such holder of Parity Lien Obligations takes or omits to take (including actions with respect to the creation, perfection or continuation of Liens on any Collateral, actions with respect to the foreclosure upon, sale, release or depreciation of, or failure to realize upon, any Collateral, and actions with respect to the collection of any claim for all or any part of the Parity Lien Obligations from any account debtor, guarantor or any other party) in accordance with the Intercreditor Agreement and the Note Documents or the valuation, use, protection or release of any security for such Parity Lien Obligations.

No Interference; Payment Over

        The Intercreditor Agreement provides that the Note Collateral Agent and each holder of Parity Lien Obligations:

(1)

will not take or cause to be taken any action the purpose or effect of which is, or could be, to make any Lien that the Note Collateral Agent or the holders of Parity Lien Obligations have on the Collateral pari passu with, or to give the Note Collateral Agent or any holder of Parity Lien Obligations any preference or priority relative to, any Lien that the Priority Lien Collateral Agent holds on behalf of the holders of any Priority Lien Obligations secured by any Collateral or any part thereof;



(2)

will not challenge or question in any proceeding the validity or enforceability of any Priority Lien Obligations or Priority Lien Documents or the validity, attachment, perfection or priority of any Lien held by the Priority Lien Collateral Agent on behalf of the holders of any Priority Lien Obligations, or the validity or enforceability of the priorities, rights or duties established by the provisions of the Intercreditor Agreement;



(3)

will not take or cause to be taken any action the purpose or effect of which is, or could be, to interfere, hinder or delay, in any manner, whether by judicial proceedings or otherwise, any sale, transfer or other disposition of the Collateral by the Priority Lien Collateral Agent or the holders of any Priority Lien Obligations in an enforcement action;



(4)

will have no right to (A) direct the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations to exercise any right, remedy or power with respect to any Collateral or (B) consent to the exercise by the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations of any right, remedy or power with respect to any Collateral;

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(5)

will not institute any suit or assert in any suit or in any Insolvency or Liquidation Proceeding, any claim against the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations seeking damages from or other relief by way of specific performance, instructions or otherwise with respect to, and neither the Priority Lien Collateral Agent nor any holders of any Priority Lien Obligations will be liable for, any action taken or omitted to be taken by the Priority Lien Collateral Agent or such holders of Priority Lien Obligations with respect to any Collateral securing such Priority Lien Obligations;



(6)

prior to the Discharge of Priority Lien Obligations, will not seek, and will waive any right, to have any Collateral or any part thereof marshaled upon any foreclosure or other disposition of such Collateral;



(7)

prior to the Discharge of Priority Lien Obligations, will not attempt, directly or indirectly, whether by judicial proceedings or otherwise, to challenge the enforceability of any provision of the Intercreditor Agreement;



(8)

will not object to forbearance by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations; and



(9)

prior to the Discharge of Priority Lien Obligations, will not assert, and thereby waive, to the fullest extent permitted by law, any right to demand, request, plead or otherwise assert or claim the benefit of any marshalling, appraisal, valuation or other similar right that may be available under applicable law with respect to the Collateral or any similar rights a junior secured creditor may have under applicable law.

        The Intercreditor Agreement provides that the Junior Lien Collateral Agent and each holder of Junior Lien Obligations:

(1)

will not take or cause to be taken any action the purpose or effect of which is, or could be, to make any Lien that the Junior Lien Collateral Agent or the holders of Junior Lien Obligations have on the Collateral pari passu with, or to give the Junior Lien Collateral Agent or any holder of Junior Lien Obligations any preference or priority relative to, any Lien that the Priority Lien Collateral Agent holds on behalf of the holders of any Priority Lien Obligations or the Note Collateral Agent holds on behalf of the holders of any Parity Lien Obligations secured by any Collateral or any part thereof;



(2)

will not challenge or question in any proceeding the validity or enforceability of any Priority Lien Obligations, Priority Lien Documents, Parity Lien Obligations or Note Documents or the validity, attachment, perfection or priority of any Lien held by the Priority Lien Collateral Agent on behalf of the holders of any Priority Lien Obligations or the Note Collateral Agent holds on behalf of the holders of any Parity Lien Obligations, or the validity or enforceability of the priorities, rights or duties established by the provisions of the Intercreditor Agreement;



(3)

will not take or cause to be taken any action the purpose or effect of which is, or could be, to interfere, hinder or delay, in any manner, whether by judicial proceedings or otherwise, any sale, transfer or other disposition of the Collateral by the Priority Lien Collateral Agent, the holders of any Priority Lien Obligations, the Note Collateral Agent or the holders of any Parity Lien Obligations in an enforcement action;



(4)

will have no right to (A) direct the Priority Lien Collateral Agent, any holder of any Priority Lien Obligations, the Note Collateral Agent or any holder of any Parity Lien Obligations to exercise any right, remedy or power with respect to any Collateral or (B) consent to the exercise by the Priority Lien Collateral Agent, any holder of any Priority Lien Obligations, the Note Collateral Agent or any holder of any Parity Lien Obligations of any right, remedy or power with respect to any Collateral;

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(5)

will not institute any suit or assert in any suit or in any Insolvency or Liquidation Proceeding, any claim against the Priority Lien Collateral Agent, any holder of any Priority Lien Obligations, the Note Collateral Agent or any holder of any Parity Lien Obligations seeking damages from or other relief by way of specific performance, instructions or otherwise with respect to, and none of the Priority Lien Collateral Agent, any holder of any Priority Lien Obligations, the Note Collateral Agent and any holder of any Parity Lien Obligations will be liable for, any action taken or omitted to be taken by the Priority Lien Collateral Agent, any other holder of any Priority Lien Obligations, the Note Collateral Agent or any other holder of any Parity Lien Obligations with respect to any Collateral securing such Priority Lien Obligations or Parity Lien Obligations, as applicable;



(6)

will not seek, and will waive any right, to have any Collateral or any part thereof marshaled upon any foreclosure or other disposition of such Collateral;



(7)

will not attempt, directly or indirectly, whether by judicial proceedings or otherwise, to challenge the enforceability of any provision of the Intercreditor Agreement;



(8)

will not object to forbearance by the Priority Lien Collateral Agent, any holder of any Priority Lien Obligations, the Note Collateral Agent or any holder of any Parity Lien Obligations; and



(9)

will not assert, and thereby waive, to the fullest extent permitted by law, any right to demand, request, plead or otherwise assert or claim the benefit of any marshalling, appraisal, valuation or other similar right that may be available under applicable law with respect to the Collateral or any similar rights a junior secured creditor may have under applicable law.

        The Intercreditor Agreement provides that if the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations obtains possession of any Collateral or realizes any proceeds or payment in respect of any Collateral, pursuant to the exercise of any rights or remedies with respect to any of the Collateral under any Security Document or Junior Lien Security Document, as applicable, or by the exercise of any rights available to it under applicable law or in any Insolvency or Liquidation Proceeding at any time prior to the Discharge of Priority Lien Obligations, then it will hold such Collateral, proceeds or payment in trust for the Priority Lien Collateral Agent and the holders of Priority Lien Obligations and transfer such Collateral, proceeds or payment, as the case may be, to the Priority Lien Collateral Agent as promptly as practicable. Each of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations have further agreed that if, at any time, any of them obtains written notice that all or part of any payment with respect to any Priority Lien Obligations previously made shall be rescinded for any reason whatsoever, they will promptly pay over to the Priority Lien Collateral Agent any payment received by them and then in their possession or under their direct control in respect of any such Priority Lien Collateral and shall promptly turn any such Collateral then held by them over to the Priority Lien Collateral Agent, and the provisions set forth in the Intercreditor Agreement will be reinstated as if such payment had not been made, until the Discharge of Priority Lien Obligations. All Parity Liens and Junior Liens will remain attached to and enforceable against all proceeds so held or remitted, subject to the priorities set forth in the Intercreditor Agreement. The Intercreditor Agreement provides that the provisions described in this paragraph will not apply to any proceeds of Collateral realized in a transaction not prohibited by the Priority Lien Documents and as to which the possession or receipt thereof by the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations, as applicable, is otherwise permitted by the Priority Lien Documents.

        The Intercreditor Agreement provides that if the Junior Lien Collateral Agent or any holder of Junior Lien Obligations obtains possession of any Collateral or realizes any proceeds or payment in respect of any Collateral, pursuant to the exercise of any rights or remedies with respect to any of the Collateral under any Junior Lien Security Document or by the exercise of any rights available to them

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under applicable law or in any Insolvency or Liquidation Proceeding, at any time after the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, then they will hold such Collateral, proceeds or payment in trust for the Note Collateral Agent and the holders of Parity Lien Obligations and transfer such Collateral, proceeds or payment, as the case may be, to the Note Collateral Agent reasonably promptly after obtaining written notice from the Note Collateral Agent or any holder of Parity Lien Obligations that they have possession of such Collateral, or proceeds or payment in respect thereof. Each of the Junior Lien Collateral Agent and the holders of Junior Lien Obligations will further agree that if, at any time, either of them obtains written notice that all or part of any payment with respect to any Parity Lien Obligations previously made shall be rescinded for any reason whatsoever, they will promptly pay over to the Note Collateral Agent any payment received by either of them and then in their possession or under their direct control in respect of any such Parity Lien Collateral and shall promptly turn any such Collateral then held by either of them over to the Note Collateral Agent, and the provisions set forth in the Intercreditor Agreement will be reinstated as if such payment had not been made, until the Discharge of Parity Lien Obligations. All Junior Liens will remain attached to and enforceable against all proceeds so held or remitted, subject to the priorities set forth in the Intercreditor Agreement. The Intercreditor Agreement provides that the provisions described in this paragraph do not apply to any proceeds of Collateral realized in a transaction not prohibited by the Note Documents and as to which the possession or receipt thereof by the Junior Lien Collateral Agent or other holders of Junior Lien Obligations is otherwise permitted by the Note Documents.

Automatic Release of Parity and Junior Liens

        The Intercreditor Agreement provides that, prior to the Discharge of Priority Lien Obligations, the Note Collateral Agent, each holder of Parity Lien Obligations, Junior Lien Collateral Agent and each holder of Junior Lien Obligations agree that, if the Priority Lien Collateral Agent or the holders of Priority Lien Obligations release their Lien on any Collateral, each of the Parity Lien and Junior Lien on such Collateral will terminate and be released automatically and without further action if (i) such release is permitted under the Note Documents and the Junior Lien Documents, (ii) such release is effected in connection with the Priority Lien Collateral Agent's foreclosure upon, or other exercise of rights or remedies with respect to, such Collateral, or (iii) such release is effected in connection with a sale or other disposition of any Collateral (or any portion thereof) under Section 363 of the Bankruptcy Code or any other provision of the Bankruptcy Code if the Priority Lien Collateral Agent and the holders of Priority Lien Obligations shall have consented to such sale or disposition of such Collateral; provided, in the case of each of clauses (i), (ii), and (iii), (A) the net proceeds of such Collateral are applied pursuant to the paragraph entitled "Application of Proceeds" and (B) the Parity Liens and Junior Liens on such Collateral securing the Parity Lien Obligations or Junior Lien Obligations, as applicable, shall remain in place (and shall remain subject and subordinate to all Priority Liens securing Priority Lien Obligations, subject to the Priority Lien Cap, and all Parity Liens securing Parity Lien Obligations) with respect to any proceeds of a sale, transfer or other disposition of Collateral not paid to the holders of Priority Lien Obligations or that remain after the Discharge of Priority Lien Obligations.

        The Intercreditor Agreement provides that, following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, the Junior Lien Collateral Agent and each holder of Junior Lien Obligations agree that, if the Note Collateral Agent or the holders of Parity Lien Obligations release their Lien on any Collateral, the Junior Lien on such Collateral securing the Junior Lien Obligations will terminate and be released automatically and without further action if (i) such release is permitted under the Junior Lien Documents, (ii) such release is effected in connection with the Note Collateral Agent's foreclosure upon, or other exercise of rights or remedies with respect to, such Collateral, or (iii) such release is effected in connection with a sale or other disposition of any Collateral (or any portion thereof) under Section 363 of the Bankruptcy Code or any other provision of

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the Bankruptcy Code if the Note Collateral Agent and the holders of Parity Lien Obligations shall have consented to such sale or disposition of such Collateral; provided, in the case of each of clauses (i), (ii), and (iii), (A) the net proceeds of such Collateral are applied pursuant to the paragraph entitled "Application of Proceeds" and (B) the Junior Liens on such Collateral securing the Junior Lien Obligations shall remain in place (and shall remain subject and subordinate to all Parity Liens securing Parity Lien Obligations) with respect to any proceeds of a sale, transfer or other disposition of Collateral not paid to the holders of Parity Lien Obligations or that remain after the Discharge of Priority Lien Obligations.

Agreements With Respect to Insolvency or Liquidation Proceedings

        The Intercreditor Agreement is a "subordination agreement" under Section 510(a) of the Bankruptcy Code. If either Issuer or any of its Subsidiaries becomes subject to any Insolvency or Liquidation Proceeding and, as debtor(s)-in-possession, or if any receiver or trustee for such Person or Persons, moves for approval of financing ("DIP Financing") to be provided by one or more lenders (the "DIP Lenders") under Section 364 of the Bankruptcy Code or the use of cash collateral under Section 363 of the Bankruptcy Code, the Intercreditor Agreement provides that none of the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent and any holder of Junior Lien Obligations will raise any objection, contest or oppose (or join or support any third party in objecting, contesting or opposing), and will waive any claim such Person may now or hereafter have, to any such financing or to the Liens on the Collateral securing the same ("DIP Financing Liens"), or to any use, sale or lease of cash collateral that constitutes Collateral or to any grant of administrative expense priority under Section 364 of the Bankruptcy Code, unless (1) the Priority Lien Collateral Agent opposes or objects to such DIP Financing, such DIP Financing Liens or such use of cash collateral, (2) the maximum principal amount of Indebtedness permitted under such DIP Financing exceeds the sum of (x) the amount of Priority Lien Obligations refinanced with the proceeds thereof (not including the amount of any Excess Priority Lien Obligations) and (y) $50 million or (3) the terms of such DIP Financing provide for the sale of a substantial part of the Collateral (other than a sale or disposition pursuant to Section 363 of the Bankruptcy Code with respect to which the Second Lien Secured Parties are deemed to have consented pursuant to the provisions described in the third paragraph under the caption "—Agreements With Respect to Insolvency or Liquidation Proceedings") or require the confirmation of a plan of reorganization containing specific terms or provisions (other than repayment in cash of such DIP Financing on the effective date thereof). To the extent such DIP Financing Liens are senior to, or rank pari passu with, the Liens on Collateral securing Priority Lien Obligations, (i) the Note Collateral Agent will, for itself and on behalf of holders of the Parity Lien Obligations, subordinate the Liens on the Collateral that secure the Parity Lien Obligations to the Liens on the Collateral that secure Priority Lien Obligations and to such DIP Financing Liens, so long as the Note Collateral Agent, on behalf of holders of the Parity Lien Obligations, retains Liens on all the Collateral, including proceeds thereof arising after the commencement of any Insolvency or Liquidation Proceeding, with the same priority relative to the Liens on the Collateral as existed prior to the commencement of the case under the Bankruptcy Code and (ii) the Junior Lien Collateral Agent will, for itself and on behalf of holders of the Junior Lien Obligations, subordinate the Liens on the Collateral that secure the Junior Lien Obligations to the Liens on the Collateral that secure Priority Lien Obligations and the Parity Lien Obligations and to such DIP Financing Liens, so long as the Junior Lien Collateral Agent, on behalf of holders of the Junior Lien Obligations, retains Liens on all the Collateral, including proceeds thereof arising after the commencement of any Insolvency or Liquidation Proceeding, with the same priority relative to the Liens on the Collateral that secure the Priority Lien Obligations and the Parity Lien Obligations as existed prior to the commencement of the case under the Bankruptcy Code. Furthermore, the Intercreditor Agreement provides that prior to the Discharge of Priority Lien Obligations, without the written consent of the Priority Lien Collateral Agent in its sole discretion, none of the Note Collateral Agent, any holder of Parity Lien Obligations,

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the Junior Lien Collateral Agent and any holder of Junior Lien Obligations will propose, support or enter into any DIP Financing.

        If either Issuer or any of its Subsidiaries becomes subject to any Insolvency or Liquidation Proceeding and, as debtor(s)-in-possession, moves for approval of DIP Financing to be provided by one or more DIP Lenders under Section 364 of the Bankruptcy Code or the use of cash collateral under Section 363 of the Bankruptcy Code, the Intercreditor Agreement provides that neither the Junior Lien Collateral Agent nor any holder of Junior Lien Obligations will raise any objection, contest or oppose, and will waive any claim such Person may now or hereafter have, to any such financing or to DIP Financing Liens, or to any use, sale or lease of cash collateral that constitutes Collateral or to any grant of administrative expense priority under Section 364 of the Bankruptcy Code, unless (1) the Note Collateral Agent or the holders of any Parity Lien Obligations oppose or object to such DIP Financing, such DIP Financing Liens or such use of cash collateral or (2) the maximum principal amount of Indebtedness permitted under such DIP Financing exceeds the sum of (x) the amount of Parity Lien Obligations refinanced with the proceeds thereof and (y) $50 million. To the extent such DIP Financing Liens are senior to, or rank pari passu with, the Liens on Collateral securing Parity Lien Obligations, the Junior Lien Collateral Agent will, for itself and on behalf of holders of the Junior Lien Obligations, subordinate the Liens on the Collateral that secure the Junior Lien Obligations to the Liens on the Collateral that secure Parity Lien Obligations and to such DIP Financing Liens, so long as the Junior Lien Collateral Agent, on behalf of holders of the Junior Lien Obligations, retains Liens on all the Collateral, including proceeds thereof arising after the commencement of any Insolvency or Liquidation Proceeding, with the same priority relative to the Liens securing Parity Lien Obligations as existed prior to the commencement of the case under the Bankruptcy Code. Furthermore, the Intercreditor Agreement provides that without the written consent of the Note Collateral Agent in its sole discretion, neither the Junior Lien Collateral Agent nor any holder of Junior Lien Obligations will propose, support or enter into any DIP Financing.

        The Intercreditor Agreement provides that the Note Collateral Agent, each holder of Parity Lien Obligations, the Junior Lien Collateral Agent and each holder of Junior Lien Obligations will not object to, oppose or contest (or join with or support any third party objecting to, opposing or contesting) a sale or other disposition, a motion to sell or dispose or the bidding procedure for such sale or disposition of any Collateral (or any portion thereof) under Section 363 of the Bankruptcy Code or any other provision of the Bankruptcy Code if (1) the Priority Lien Collateral Agent or the requisite holders of Priority Lien Obligations shall have consented to such sale or disposition of such Collateral, (2) all Parity Liens and Junior Liens on the Collateral securing the Parity Lien Obligations and Junior Lien Obligations, as applicable, shall attach to the proceeds of such sale in the same respective priorities as set forth in the Intercreditor Agreement with respect to the Collateral, (3) the waterfall described in the "Application of Proceeds" paragraph is complied with in connection with such credit bid and (4) each of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations shall have the right to credit bid all or any portion of the Collateral so long as the Priority Lien Collateral Agent and the holders of the Priority Lien Obligations receive payment in full in cash of all Priority Lien Obligations after giving effect thereto. The Intercreditor Agreement further provides that the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations will waive any claim that may be had against the Priority Lien Collateral Agent or any holder of Priority Lien Obligations arising out of any DIP Financing Liens (granted in a manner that is consistent with the Intercreditor Agreement) or administrative expense priority under Section 364 of the Bankruptcy Code. The Intercreditor Agreement further provides that the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations will not file or prosecute in any Insolvency or Liquidation Proceeding any motion for adequate protection (or any comparable request for relief) based upon their interest in the Collateral, and will not object to, oppose or contest (or join with or support any third party objecting to, opposing

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or contesting) (a) any request by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations for adequate protection or (b) any objection by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations to any motion, relief, action or proceeding based on the Priority Lien Collateral Agent or any holder of Priority Lien Obligations claiming a lack of adequate protection, except that the Note Collateral Agent and the holders of Parity Lien Obligations:

(1)

may freely seek and obtain relief granting adequate protection only in the form of a replacement lien co-extensive in all respects with, but subordinated to, and with the same relative priority to the Priority Liens and the Junior Liens as existed prior to the commencement of the Insolvency or Liquidation Proceeding, all Liens granted in the Insolvency or Liquidation Proceeding to, or for the benefit of, the holders of the Priority Lien Obligations;



(2)

with the prior written consent of the Priority Lien Collateral Agent, may seek and obtain relief granting a superpriority claim co-extensive in all respect with (but junior to) any such claims granted in the Insolvency or Liquidation Proceeding to or for the benefit of the holders of the Priority Lien Obligations and relating to the Collateral; provided, that any payments or proceeds in respect of such superpriority claim shall be considered proceeds of Collateral for purposes of the caption "—No Interference; Payment Over"; and



(3)

may freely seek and obtain any relief upon a motion for adequate protection (or any comparable relief), without any condition or restriction whatsoever, at any time after the Discharge of Priority Lien Obligations; and



(4)

the Junior Lien Collateral Agent and the holders of Junior Lien Obligations:



(5)

may freely seek and obtain relief granting adequate protection only in the form of a replacement lien co-extensive in all respects with, but subordinated to, and with the same relative priority to the Priority Liens and the Parity Liens as existed prior to the commencement of the Insolvency or Liquidation Proceeding, all Liens granted in the Insolvency or Liquidation Proceeding to, or for the benefit of, the holders of the Priority Lien Obligations and the holders of the Parity Lien Obligations;



(6)

with the prior written consent of the Priority Lien Collateral Agent and the Parity Lien Agent, may seek and obtain relief granting a superpriority claim co-extensive in all respect with (but junior to) any such claims granted in the Insolvency or Liquidation Proceeding to or for the benefit of the holders of the Priority Lien Obligations and the holders of the Parity Lien Obligations and relating to the Collateral; provided, that any payments or proceeds in respect of such superpriority claim shall be considered proceeds of Collateral for purposes of the caption "—No Interference; Payment Over"; and



(7)

may freely seek and obtain any relief upon a motion for adequate protection (or any comparable relief), without any condition or restriction whatsoever, at any time after the Discharge of Priority Lien Obligations and the Discharge of Parity Lien Obligations.

        The Intercreditor Agreement provides that the Junior Lien Collateral Agent and each holder of Junior Lien Obligations will not object to, oppose or contest (or join with or support any third party objecting to, opposing or contesting) a sale or other disposition, a motion to sell or dispose or the bidding procedure for such sale or disposition of any Collateral (or any portion thereof) under Section 363 of the Bankruptcy Code or any other provision of the Bankruptcy Code if (1) the Note Collateral Agent or the requisite holders of Parity Lien Obligations shall have consented to such sale or disposition, a motion to sell or dispose or the bidding procedure for such sale or disposition of such Collateral, (2) all Junior Liens on the Collateral securing the Junior Lien Obligations shall attach to the proceeds of such sale in the same respective priorities as set forth in the Intercreditor Agreement with respect to the Collateral, (3) the waterfall described in the "Application of Proceeds" paragraph is

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complied with in connection with such credit bid and (4) each of the Junior Lien collateral Agent and the holders of Junior Lien Obligations shall have the right to credit bid all or any portion of the collateral so long as the Note Collateral Agent and the holders of the Parity Lien Obligations receive payment in full in cash of all Parity Lien Obligations after giving effect thereto. The Intercreditor Agreement further provides that the Junior Lien Collateral Agent and the holders of Junior Lien Obligations will waive any claim that may be had against the Note Collateral Agent or any holder of Parity Lien Obligations arising out of any DIP Financing Liens (granted in a manner that is consistent with the Intercreditor Agreement) or administrative expense priority under Section 364 of the Bankruptcy Code. The Intercreditor Agreement further provides that the Junior Lien Collateral Agent and the holders of Junior Lien Obligations will not file or prosecute in any Insolvency or Liquidation Proceeding any motion for adequate protection (or any comparable request for relief) based upon their interest in the Collateral, and will not object to, oppose or contest (or join with or support any third party objecting to, opposing or contesting) (a) any request by the Note Collateral Agent or any holder of Parity Lien Obligations for adequate protection or (b) any objection by the Note Collateral Agent or any holder of Parity Lien Obligations to any motion, relief, action or proceeding based on the Note Collateral Agent or any holder of Parity Lien Obligations claiming a lack of adequate protection, except that the Junior Lien Collateral Agent and the holders of Junior Lien Obligations:

(1)

may freely seek and obtain relief granting adequate protection only in the form of a replacement lien co-extensive in all respects with, but subordinated to, and with the same relative priority to the Parity Liens as existed prior to the commencement of the Insolvency or Liquidation Proceeding, all Liens granted in the Insolvency or Liquidation Proceeding to, or for the benefit of, the holders of the Parity Lien Obligations;



(2)

with the prior written consent of the Parity Lien Agent, may seek and obtain relief granting a superpriority claim co-extensive in all respect with (but junior to) any such claims granted in the Insolvency or Liquidation Proceeding to or for the benefit of the holders of the Parity Lien Obligations and relating to the Collateral; provided, that any payments or proceeds in respect of such superpriority claim shall be considered proceeds of Collateral for purposes of the caption "—No Interference; Payment Over,"; and



(3)

may freely seek and obtain any relief upon a motion for adequate protection (or any comparable relief), without any condition or restriction whatsoever, at any time after the Discharge of Parity Lien Obligations.

        In any Insolvency or Liquidation Proceeding, none of the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent and any holder of Junior Lien Obligations shall support or vote for any plan of reorganization or disclosure statement of the Issuers or any Guarantor unless such plan is accepted by the class of holders of the Priority Lien Obligations in accordance with Section 1126(c) of the Bankruptcy Code or otherwise provides for the payment in full in cash of all Priority Lien Obligations on the effective date of such plan of reorganization or except as otherwise provided in the Intercreditor Agreement, the holders of the Parity Lien Obligations and the holders of the Junior Lien Obligations shall remain entitled to vote their claims in any such Insolvency or Liquidation Proceeding.

        In any Insolvency or Liquidation Proceeding, neither the Junior Lien Collateral Agent nor any holder of Junior Lien Obligations shall support or vote for any plan of reorganization or disclosure statement of either the Issuers or any Guarantor unless such plan is accepted by the class of holders of the Parity Lien Obligations in accordance with Section 1126(c) of the Bankruptcy Code or otherwise provides for the payment in full in cash of all Parity Lien Obligations on the effective date of such plan of reorganization. Except as otherwise provided in the Intercreditor Agreement, the holders of the Junior Lien Obligations shall remain entitled to vote their claims in any such Insolvency or Liquidation Proceeding.

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        The Intercreditor Agreement additionally provides that the Note Collateral Agent, each holder of Parity Lien Obligations, the Junior Lien Collateral Agent and each holder of Junior Lien Obligations will waive any claim that may be had against the Priority Lien Collateral Agent or any holder of any Priority Lien Obligations arising out of any election by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in any proceeding instituted under the Bankruptcy Code, of the application of Section 1111(b) of the Bankruptcy Code.

        The Intercreditor Agreement additionally provides that the Junior Lien Collateral Agent and each holder of Junior Lien Obligations will waive any claim that may be had against the Note Collateral Agent or any holder of any Parity Lien Obligations arising out of any election by the Note Collateral Agent or any holder of Parity Lien Obligations in any proceeding instituted under the Bankruptcy Code, of the application of Section 1111(b) of the Bankruptcy Code.

        Until the Discharge of Priority Lien Obligations has occurred, none of the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall seek relief, pursuant to Section 362(d) of the Bankruptcy Code or otherwise, from the automatic stay of Section 362(a) of the Bankruptcy Code or from any other stay in any Insolvency or Liquidation Proceeding in respect of the Collateral if the Priority Lien Collateral Agent has not received relief from the automatic stay (or it has not been lifted for the Priority Lien Collateral Agent's benefit), without the prior written consent of the Priority Lien Collateral Agent.

        Following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, neither the Junior Lien Collateral Agent nor any holder of Junior Lien Obligations shall seek relief, pursuant to Section 362(d) of the Bankruptcy Code or otherwise, from the automatic stay of Section 362(a) of the Bankruptcy Code or from any other stay in any Insolvency or Liquidation Proceeding in respect of the Collateral, without the prior written consent of the Note Collateral Agent.

        None of the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall oppose or seek to challenge any claim by the Priority Lien Collateral Agent or any other holder of Priority Lien Obligations for allowance (but not payment until the Discharge of Priority Lien Obligations has occurred) in any Insolvency or Liquidation Proceeding of Priority Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the Priority Liens (it being understood that such value will be determined without regard to the existence of the Parity Liens or the Junior Liens on the Collateral). Neither the Priority Lien Collateral Agent nor any holder of Priority Lien Obligations shall oppose or seek to challenge any claim by the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations for allowance (but not payment until the Discharge of Priority Lien Obligations has occurred) in any Insolvency or Liquidation Proceeding of Parity Lien Obligations or Junior Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the Parity Liens or Junior Liens, as applicable, on the Collateral; provided that if the Priority Lien Collateral Agent or any holder of Priority Lien Obligations shall have made any such claim, such claim (i) shall have been approved or (ii) will be approved contemporaneously with the approval of any such claim by the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations, as applicable.

        Neither the Junior Lien Collateral Agent nor any holder of Junior Lien Obligations shall oppose or seek to challenge any claim by the Note Collateral Agent or any other holder of Parity Lien Obligations for allowance (but not payment until the Discharge of Priority Lien Obligations has occurred) in any Insolvency or Liquidation Proceeding of Parity Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the Parity Liens (it being understood that such value will be determined without regard to the existence of the Junior Liens on the Collateral). Neither the Note Collateral Agent nor any holder of Parity Lien Obligations shall oppose or seek to challenge any claim by the Junior Lien Collateral Agent or any holder of Junior Lien

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Obligations for allowance (but not payment until the Discharge of Priority Lien Obligations has occurred) in any Insolvency or Liquidation Proceeding of Junior Lien Obligations consisting of post-petition interest, fees or expenses to the extent of the value of the Junior Liens on the Collateral; provided that if the Note Collateral Agent or any holder of Parity Lien Obligations shall have made any such claim, such claim (i) shall have been approved or (ii) will be approved contemporaneously with the approval of any such claim by the Junior Lien Collateral Agent or any holder of Junior Lien Obligations.

        Without the express written consent of the Priority Lien Collateral Agent, none of the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall (or shall join with or support any third party in opposing, objecting to or contesting, as the case may be), in any Insolvency or Liquidation Proceeding involving the Issuers or any Guarantor, (i) oppose, object to or contest the determination of the extent of any Liens held by any of holder of Priority Lien Obligations or the value of any claims of any such holder under Section 506(a) of the Bankruptcy Code or (ii) oppose, object to or contest the payment to the holder of Priority Lien Obligations of interest, fees or expenses, or to the cash collateralization of letters of credit, under Section 506(b) of the Bankruptcy Code.

        Without the express written consent of the Note Collateral Agent, neither the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall (or shall join with or support any third party in opposing, objecting to or contesting, as the case may be), in any Insolvency or Liquidation Proceeding involving the Issuers or any Guarantor, (i) oppose, object to or contest the determination of the extent of any Liens held by any of holder of Parity Lien Obligations or the value of any claims of any such holder under Section 506(a) of the Bankruptcy Code or (ii) oppose, object to or contest the payment to the holder of Parity Lien Obligations of interest, fees or expenses under Section 506(b) of the Bankruptcy Code.

        Notwithstanding anything to the contrary contained in the Intercreditor Agreement, if in any Insolvency or Liquidation Proceeding a determination is made that any Lien encumbering any Collateral is not enforceable for any reason, the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations agree that any distribution or recovery they may receive in respect of any Collateral shall be segregated and held in trust and forthwith paid over to the Priority Lien Collateral Agent for the benefit of the holders of Priority Lien Obligations in the same form as received without recourse, representation or warranty (other than a representation of the Note Collateral Agent or the Junior Lien Collateral Agent, as applicable, that it has not otherwise sold, assigned, transferred or pledged any right, title or interest in and to such distribution or recovery) but with any necessary endorsements or as a court of competent jurisdiction may otherwise direct. Each of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations appoint the Priority Lien Collateral Agent, and any officer or agent of the Priority Lien Collateral Agent, with full power of substitution, the attorney-in-fact of each the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations for the limited purpose of carrying out the provisions related to this paragraph and taking any action and executing any instrument that the Priority Lien Collateral Agent may deem necessary or advisable to accomplish the purposes of this paragraph, which appointment is irrevocable and coupled with an interest.

        Notwithstanding anything to the contrary contained in the Intercreditor Agreement, if in any Insolvency or Liquidation Proceeding a determination is made that any Lien encumbering any Collateral is not enforceable for any reason, then the Junior Lien Collateral Agent and the holders of Junior Lien Obligations agree that any distribution or recovery they may receive in respect of any Collateral shall be segregated and held in trust and following the Discharge of Priority Lien Obligations forthwith paid over to the Note Collateral Agent for the benefit of the holders of Parity Lien

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Obligations in the same form as received without recourse, representation or warranty (other than a representation of the Junior Lien Collateral Agent that it has not otherwise sold, assigned, transferred or pledged any right, title or interest in and to such distribution or recovery) but with any necessary endorsements or as a court of competent jurisdiction may otherwise direct. The Junior Lien Collateral Agent and the holders of Junior Lien Obligations appoint the Note Collateral Agent, and any officer or agent of the Note Collateral Agent, with full power of substitution, the attorney-in-fact of each of Junior Lien Collateral Agent and the holders of Junior Lien Obligations for the limited purpose of carrying out the provisions of this paragraph and taking any action and executing any instrument that the Note Collateral Agent may deem necessary or advisable to accomplish the purposes of this paragraph, which appointment is irrevocable and coupled with an interest.

        The Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations have agreed that the Priority Lien Collateral Agent shall have the exclusive right to credit bid the Priority Lien Obligations and further that none of the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall (or shall join with or support any third party in opposing, objecting to or contesting, as the case may be) oppose, object to or contest such credit bid by the Priority Lien Collateral Agent; provided that (A) the waterfall described in the "Application of Proceeds" paragraph is complied with in connection with such credit bid and (B) each of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations shall have the right to credit bid all or any portion of the Collateral so long as the Priority Lien Collateral Agent and the holders of the Priority Lien Obligations receive payment in full in cash of all Priority Lien Obligations after giving effect thereto.

        The Junior Lien Collateral Agent and the holders of Junior Lien Obligations have agreed that the Note Collateral Agent shall have the exclusive right to credit bid the Parity Lien Obligations and further that neither the Junior Lien Collateral Agent nor any other holder of Junior Lien Obligations shall (or shall join with or support any third party in opposing, objecting to or contesting, as the case may be) oppose, object to or contest such credit bid by the Note Collateral Agent; provided that (A) the waterfall described in the "Application of Proceeds" paragraph is complied with in connection with such credit bid and (B) the Junior Lien Collateral Agent or the holders of Junior Lien Obligations shall have the right to credit bid all or any portion of the Collateral so long as the Note Collateral Agent and the holders of the Parity Lien Obligations receive payment in full in cash of all Parity Lien Obligations after giving effect thereto.

        Until the expiry of the Parity Lien Standstill Period, in the case of the Note Collateral Agent and the holders of Parity Lien Obligations, and the expiry of the Junior Lien First Standstill Period, in the case of the Junior Lien Collateral Agent and the holders of Junior Lien Obligations, without the prior written consent of the Priority Lien Collateral Agent in its sole discretion, each of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations agree they will not file an involuntary bankruptcy claim or seek the appointment of an examiner or a trustee.

        Until the expiry of the Junior Lien Second Standstill Period, without the prior written consent of the Note Collateral Agent in its sole discretion, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations agree they will not file an involuntary bankruptcy claim or seek the appointment of an examiner or a trustee.

        Each of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations waives any right to assert or enforce any claim under Section 506(c) or 552 of the Bankruptcy Code as against the Priority Lien Collateral Agent, the holders of Priority Lien Obligations or any of the Collateral.

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        Each of the Junior Lien Collateral Agent and the holders of Junior Lien Obligations waives any right to assert or enforce any claim under Section 506(c) or 552 of the Bankruptcy Code as against the Note Collateral Agent, any holder of Parity Lien Obligations or any of the Collateral.

Notice Requirements and Procedural Provisions

        The Intercreditor Agreement also provides for various advance notice requirements and other procedural provisions typical for agreements of this type, including procedural provisions to allow any successor Priority Lien Collateral Agent to become a party to the Intercreditor Agreement (without the consent of any holder of Priority Lien Obligations, Parity Lien Obligations (including holders of the notes) or Junior Lien Obligations) upon the refinancing or replacement of the Priority Lien Obligations or Priority Lien Debt Obligations as permitted by the applicable Priority Lien Documents and the Note Documents.

No New Liens; Similar Documents

        So long as the Discharge of Priority Lien Obligations has not occurred, neither the Company nor any of its Subsidiaries shall grant or permit any additional Liens, or take any action to perfect any additional Liens, on any property to secure:

(1)

any Junior Lien Obligation unless it has also granted or substantially contemporaneously grants (or offers to grant) a Lien on such property to secure (x) the Priority Lien Obligations and has taken all actions required to perfect such Liens and (y) the Parity Lien Obligations and has taken all actions required to perfect such Liens; provided, however, the refusal or inability of the Priority Lien Collateral Agent or the Note Collateral Agent to accept such Lien will not prevent the Junior Lien Collateral Agent from taking the Lien;



(2)

any Parity Lien Obligation unless it has also granted or substantially contemporaneously grants (or offers to grant) a Lien on such property to secure (x) the Priority Lien Obligations and has taken all actions required to perfect such Liens and (y) the Junior Lien Obligations and has taken all actions required to perfect such Liens; provided, however, the refusal or inability of the Priority Lien Collateral Agent or the Junior Lien Collateral Agent to accept such Lien will not prevent the Note Collateral Agent from taking the Lien; or



(3)

any Priority Lien Obligation unless it has also granted or substantially contemporaneously grants (or offers to grant) a Lien on such property to secure (x) the Parity Lien Obligations and has taken all actions required to perfect such Liens and (y) the Junior Lien Obligations and has taken all actions required to perfect such Liens provided, however, the refusal, inability or delay of the Note Collateral Agent or the Junior Lien Collateral Agent to accept such Lien will not prevent the Priority Lien Collateral Agent from taking the Lien,

with each such Lien to be subject to the provisions of the Intercreditor Agreement.

        After the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, neither the Company nor any of its Subsidiaries shall grant or permit any additional Liens, or take any action to perfect any additional Liens, on any property to secure:

(1)

any Parity Lien Obligation unless it has also granted or substantially contemporaneously grants (or offers to grant) a Lien on such property to secure the Junior Lien Obligations and has taken all actions required to perfect such Liens; provided, however, the refusal or inability of the Junior Lien Collateral Agent to accept such Lien will not prevent the Note Collateral Agent from taking the Lien; or



(2)

any Junior Lien Obligation unless it has also granted or substantially contemporaneously grants (or offers to grant) a Lien on such property to secure the Parity Lien Obligations and

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has taken all actions required to perfect such Liens provided, however, the refusal or inability of the Note Collateral Agent to accept such Lien will not prevent the Junior Lien Collateral Agent from taking the Lien,

with each such Lien to be subject to the provisions of the Intercreditor Agreement.

        To the extent that the foregoing provisions are not complied with for any reason, without limiting any other rights and remedies available to the Priority Lien Collateral Agent and/or the other holders of Priority Lien Obligations, the Note Collateral Agent or the holders of Parity Lien Obligations, each of the Note Collateral Agent, the holders of the Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations have agreed that any amounts received by or distributed to any of them pursuant to or as a result of Liens granted in contravention of this paragraph shall be subject to the Intercreditor Agreement. The Intercreditor Agreement also provides for further undertakings by the Note Collateral Agent, the Priority Lien Collateral Agent and the Junior Lien Collateral Agent and agreements that (x) all Note Security Documents providing for the Parity Liens shall be in all material respects the same forms of documents providing for the Priority Liens other than as to the priority nature, other modifications that make the Note Security Documents with respect to the Parity Liens less restrictive than the corresponding documents with respect to the Priority Liens, provisions in the Note Security Documents for the Parity Liens which relate solely to rights and duties of the Note Collateral Agent and the holders of the Parity Lien Obligations and such deletions or modifications of representations, warranties and covenants as are customary with respect to security documents establishing Liens securing publicly traded debt securities and (y) all security documents providing for the Junior Liens shall be in all material respects the same forms of documents providing for Priority Liens and Parity Liens other than as to the priority nature, other modifications that make the security documents with respect to the Junior Liens less restrictive than the corresponding documents with respect to the Priority Liens and Parity Liens and provisions in the security documents for the Junior Liens which relate solely to rights and duties of the Junior Lien Collateral Agent and the holders of the Junior Lien Obligations and such deletions or modifications of representations, warranties and covenants as are customary with respect to security documents establishing Liens securing publicly traded debt securities (to the extent applicable).

Insurance

        Unless and until the Discharge of Priority Lien Obligations has occurred (but subject to the rights of the Note Collateral Agent, the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of Junior Lien Obligations following expiration of any of the Parity Lien Standstill Period, the Junior Lien First Standstill Period or Junior Lien Second Standstill Period, as applicable, as provided in the paragraphs defining "Parity Lien Standstill Period," "Junior Lien First Standstill Period" and "Junior Lien Second Standstill Period"), the Priority Lien Collateral Agent shall have the sole and exclusive right, subject to the rights of the obligors under the Priority Lien Documents, to adjust and settle claims in respect of Collateral under any insurance policy in the event of any loss thereunder and to approve any award granted in any condemnation or similar proceeding (or any deed in lieu of condemnation) affecting the Collateral. Unless and until the Discharge of Priority Lien Obligations has occurred, and subject to the rights of the obligors under the Priority Lien Documents, all proceeds of any such policy and any such award (or any payments with respect to a deed in lieu of condemnation) in respect of the Collateral shall be paid to the Priority Lien Collateral Agent pursuant to the terms of the Priority Lien Documents (including for purposes of cash collateralization of letters of credit). If the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall, at any time, knowingly receive any proceeds of any such insurance policy or any such award or payment in contravention of the foregoing, it shall pay such proceeds over to the Priority Lien Collateral Agent in accordance with the Intercreditor Agreement. In addition, if by virtue of being named as an additional insured or loss payee

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of any insurance policy of any obligor covering any of the Collateral, the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall have the right to adjust or settle any claim under any such insurance policy, then unless and until the Discharge of Priority Lien Obligations has occurred, the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall follow the instructions of the Priority Lien Collateral Agent, or of the obligors under the Priority Lien Documents to the extent the Priority Lien Documents grant such obligors the right to adjust or settle such claims, with respect to such adjustment or settlement (subject to the rights of the Note Collateral Agent and the holders of Parity Lien Obligations, the Junior Lien Collateral Agent and the holders of the Junior Lien Obligations following expiration of the Parity Lien Standstill Period, the Junior Lien First Standstill Period or Junior Lien Second Standstill Period, as applicable, as provided in the paragraphs defining "Parity Lien Standstill Period," "Junior Lien First Standstill Period" and "Junior Lien Second Standstill Period").

        Following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations has occurred (but subject to the rights of the Junior Lien Collateral Agent and the holders of Junior Lien Obligations following expiration of the Junior Lien Second Standstill Period, as provided in the paragraphs defining "Junior Lien Second Standstill Period"), the Note Collateral Agent shall have the sole and exclusive right, subject to the rights of the obligors under the Note Documents, to adjust and settle claims in respect of Collateral under any insurance policy in the event of any loss thereunder and to approve any award granted in any condemnation or similar proceeding (or any deed in lieu of condemnation) affecting the Collateral. Unless and until the Discharge of Parity Lien Obligations has occurred, and subject to the rights of the obligors under the Note Documents, all proceeds of any such policy and any such award (or any payments with respect to a deed in lieu of condemnation) in respect to the Collateral shall be paid to the Note Collateral Agent pursuant to the terms of the Note Documents and, after the Discharge of Parity Lien Obligations has occurred, to the Junior Lien Collateral Agent to the extent required under the Junior Lien security documents and then, to the extent no Junior Lien Obligations are outstanding, to the owner of the subject property, to such other person as may be entitled thereto or as a court of competent jurisdiction may otherwise direct. If the Junior Lien Collateral Agent or any holder of Junior Lien Obligations shall, at any time following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, receive any proceeds of any such insurance policy or any such award or payment in contravention of the foregoing, it shall pay such proceeds over to the Note Collateral Agent in accordance with the Intercreditor Agreement. In addition, if by virtue of being named as an additional insured or loss payee of any insurance policy of any obligor covering any of the Collateral, the Junior Lien Collateral Agent or any other holder of Junior Lien Obligations shall have the right to adjust or settle any claim under any such insurance policy, then unless and until the Discharge of Parity Lien Obligations has occurred, the Junior Lien Collateral Agent and any such holder of Junior Lien Obligations shall follow the instructions of the Note Collateral Agent, or of the obligors under the Note Documents to the extent the Note Documents grant such obligors the right to adjust or settle such claims, with respect to such adjustment or settlement (subject to the rights of the Junior Lien Collateral Agent and the holders of Junior Lien Obligations following expiration of the Junior Lien Second Standstill Period, as provided in the paragraphs defining "Junior Lien Second Standstill Period").

Amendment to Secured Debt Documents

        Prior to the Discharge of Priority Lien Obligations, without the prior written consent of the Priority Lien Collateral Agent, no Parity Lien Document or Junior Lien Document may be amended, supplemented, restated or otherwise modified and/or refinanced or entered into to the extent such amendment, supplement, restatement or modification and/or refinancing, or the terms of any new Parity Lien Document or Junior Lien Document, as applicable, would (i) adversely affect the lien

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priority rights of the Priority Lien Collateral Agent and the holders of Priority Lien Obligations or the rights of the Priority Lien Collateral Agent and the holders of Priority Lien Obligations to receive payments owing pursuant to the Priority Lien Documents, (ii) except as otherwise provided for in the Intercreditor Agreement, add any Liens securing the Collateral granted under the Note Documents or the Junior Lien Documents, (iii) confer any additional rights on the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations in a manner adverse to the Priority Lien Collateral Agent or the holders of Priority Lien Obligations, (iv) contravene the provisions of the Intercreditor Agreement or the Priority Lien Documents or (v) modify any Parity Lien Document or any Junior Lien Document in any manner that would not have been permitted under the Priority Lien Documents to have been included in such Parity Lien Document or any Junior Lien Document if such Parity Lien Document or any Junior Lien Document, respectively, was entered into as of the date of such amendment, supplement, restatement or modification.

        Prior to the Discharge of Parity Lien Obligations, without the prior written consent of the Parity Lien Collateral Agent, no Junior Lien Document may be amended, supplemented, restated or otherwise modified and/or refinanced or entered into to the extent such amendment, supplement, restatement or modification and/or refinancing, or the terms of any new Junior Lien Document, would (i) adversely affect the lien priority rights of the Parity Lien Collateral Agent and the holders of Parity Lien Obligations or the rights of the Parity Lien Collateral Agent and the holders of Parity Lien Obligations to receive payments owing pursuant to the Parity Lien Documents, (ii) except as otherwise provided for in the Intercreditor Agreement, add any Liens securing the Collateral granted under the Junior Lien Documents, (iii) confer any additional rights on the Junior Lien Collateral Agent or any holder of Junior Lien Obligations in a manner adverse to the Parity Lien Collateral Agent or the holders of Priority Lien, (iv) contravene the provisions of the Intercreditor Agreement or the Parity Lien Documents or (v) modify any Junior Lien Document in any manner that would not have been permitted under the Parity Lien Documents to have been included in such any Junior Lien Document if such Junior Lien Document was entered into as of the date of such amendment, supplement, restatement or modification.

Purchase Option of the Parity Lien Purchasers

        Notwithstanding anything in the Intercreditor Agreement to the contrary, on or at any time after (i) the commencement of an Insolvency or Liquidation Proceeding or (ii) the acceleration of the Priority Lien Obligations (each, a "Priority Lien Trigger Event"), each of the holders of the Parity Lien Debt and each of their respective designated affiliates (the "Parity Lien Purchasers") will have the right, at their sole option and election (but will not be obligated), at any time after the occurrence of the first Priority Lien Trigger Event (but only if Junior Lien Purchasers shall not have exercised their option described below by sixty (60) days after the occurrence of the first Priority Lien Trigger Event unless such option shall have expired as described below) upon prior written notice to the applicable Priority Lien Representative, to purchase from the holders of the Priority Lien Obligations all (but not less than all) Priority Lien Obligations (including unfunded commitments) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations and any loans provided by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing that are outstanding on the date of such purchase. Promptly following the receipt of such notice the applicable Priority Lien Representative will deliver to the Parity Lien Purchaser Representative a statement of the amount of Priority Lien Debt, other Priority Lien Obligations (other than any Priority Lien Obligations constituting Excess Priority Lien Obligations) and DIP Financing provided by any of the Priority Lien Collateral Agent or holder of the Priority Lien Obligations, if any, then outstanding and the amount of the cash collateral requested by the applicable Priority Lien Representative to be delivered pursuant to clause (2) of the immediately following paragraph. The right to purchase provided for in this paragraph will expire unless, within 20 Business Days after the receipt by the Parity

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Lien Purchaser Representative of such statement from the applicable Priority Lien Representative, the Parity Lien Purchaser Representative delivers to the applicable Priority Lien Representative an irrevocable commitment of the Parity Lien Purchasers to purchase all (but not less than all) of the Priority Lien Obligations (including unfunded commitments) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing and to otherwise complete the purchase on the terms set forth under this provision.

        On the date specified by the Parity Lien Purchaser Representative (on behalf of the Parity Lien Purchasers) in such irrevocable commitment (which shall not be less than five Business Days, nor more than 20 Business Days, after the receipt by the applicable Priority Lien Representative of such irrevocable commitment), the holders of the Priority Lien Obligations shall sell to the Parity Lien Purchasers all (but not less than all) Priority Lien Obligations (including unfunded commitments) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations and any loans provided by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing that are outstanding on the date of such sale, subject to any required approval of any court or other regulatory or governmental authority then in effect, if any, and only if on the date of such sale, the applicable Priority Lien Representative receives the following:

(1)

payment, as the purchase price for all Priority Lien Obligations sold in such sale, of an amount equal to the full amount of all Priority Lien Obligations (other than outstanding letters of credit as referred to in the clause (2) of this paragraph) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations and loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing then outstanding (including principal, interest, fees, reasonable attorneys' fees and legal expenses, but excluding contingent indemnification Obligations for which no claim or demand for payment has been made at or prior to such time); provided that in the case of Obligations in respect of Hedging Obligations that are secured by the Priority Liens, the Parity Lien Purchasers shall cause the applicable agreements governing such Hedging Obligations to be assigned and novated or, if such agreements have been terminated, such purchase price shall include an amount equal to the sum of any unpaid amounts then due in respect of such Hedging Obligations, calculated using the market quotation method and after giving effect to any netting arrangements;



(2)

a cash collateral deposit in such amount as the applicable Priority Lien Representative determines is reasonably necessary to secure the payment of any outstanding letters of credit constituting Priority Lien Debt that may become due and payable after such sale (but not in any event in an amount greater than one hundred five percent (105%) of the amount then reasonably estimated by the applicable Priority Lien Representative to be the aggregate outstanding amount of such letters of credit at such time), which cash collateral shall be (A) held by the applicable Priority Lien Representative as security solely to reimburse the issuers of such letters of credit that become due and payable after such sale and any fees and expenses incurred in connection with such letters of credit and (B) returned to the Parity Lien Purchaser Representative (except as may otherwise be required by applicable law or any order of any court or other governmental authority) promptly after the expiration or termination from time to time of all payment contingencies affecting such letters of credit; and



(3)

any agreements, documents or instruments which the applicable Priority Lien Representative may reasonably request pursuant to which the Parity Lien Purchaser Representative and the Parity Lien Purchasers in such sale expressly assume and adopt all of the Obligations of the applicable Priority Lien Representative and the holders of the Priority Lien Obligations under the documents providing for the Priority Lien and in connection with loans provided by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a

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DIP Financing on and after the date of the purchase and sale and the Parity Lien Purchaser Representative (or any other representative appointed by the holders of a majority in aggregate principal amount of the Parity Lien Obligations owned by the purchasers) becomes a successor agent thereunder.

        Such purchase of the Priority Lien Obligations (including unfunded commitments) and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing shall be made on a pro rata basis among the Parity Lien Purchasers giving notice to the applicable Priority Lien Representative of their interest to exercise the purchase option under the Intercreditor Agreement according to each such holder's portion of the Parity Lien Debt owned by the purchasers or as such Parity Lien Purchasers may otherwise agree. Such purchase price and cash collateral shall be remitted by wire transfer in federal funds to such bank account of the applicable Priority Lien Representative as the applicable Priority Lien Representative may designate in writing to the Parity Lien Purchaser Representative for such purpose. Interest shall be calculated to but excluding the Business Day on which such sale occurs if the amounts so paid by the Parity Lien Purchaser Representative and holders of the Parity Lien Debt to the bank account designated by the applicable Priority Lien Representative are received in such bank account prior to 12:00 noon, New York City time, and interest shall be calculated to and including such Business Day if the amounts so paid by the Parity Lien Purchaser Representative and holders of the Parity Lien Debt to the bank account designated by the applicable Priority Lien Representative are received in such bank account later than 12:00 noon, New York City time.

        Such sale shall be expressly made without representation or warranty of any kind by the applicable Priority Lien Representative and the holders of Priority Lien Obligations as to the Priority Lien Obligations, the Collateral or otherwise and without recourse to the applicable Priority Lien Representative and the holders of Priority Lien Obligations, except that the applicable Priority Lien Representative and the holders of Priority Lien Obligations shall represent and warrant severally as to the Priority Lien Obligations (including unfunded commitments) and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing then owing to them: (i) that the applicable Priority Lien Representative and such holders of the Priority Lien Obligations own the Priority Lien Obligations (including unfunded commitments) and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing; and (ii) the applicable Priority Lien Representative and such holders of the Priority Lien Obligations have the necessary corporate or other governing authority to assign such interests.

        After such sale becomes effective, the outstanding letters of credit will remain enforceable against the issuers thereof and will be secured solely by the cash collateral provided pursuant to the preceding clause (2) of this paragraph.

Purchase Option of the Junior Lien Purchasers

        Notwithstanding anything in the Intercreditor Agreement to the contrary, on or at any time after (i) a Priority Lien Trigger Event has occurred, (ii) the commencement of an Insolvency or Liquidation Proceeding or (iii) the acceleration of the Parity Lien Obligations, each of the holders of the Junior Lien Debt and each of their respective designated affiliates (the "Junior Lien Purchasers") will have the right, at their sole option and election (but will not be obligated), at any time within sixty (60) days after the occurrence of the first Priority Lien Trigger Event upon prior written notice to the applicable Priority Lien Representative and Parity Lien Representative, to purchase from the holders of the Priority Lien Obligations and the Parity Lien Obligations (x) all (but not less than all) Priority Lien Obligations (including unfunded commitments) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations, (y) any loans provided by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing that are outstanding on the

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date of such purchase and (z) all (but not less than all) Parity Lien Obligations. Promptly following the receipt of such notice, (i) the applicable Priority Lien Representative will deliver to the Junior Lien Purchaser Representative a statement of the amount of Priority Lien Debt, other Priority Lien Obligations (other than any Priority Lien Obligations constituting Excess Priority Lien Obligations) and DIP Financing provided by any of the Priority Lien Collateral Agent or holder of the Priority Lien Obligations, if any, then outstanding and the amount of the cash collateral requested by the applicable Priority Lien Representative to be delivered pursuant to clause (2) of the immediately following paragraph and (ii) the applicable Parity Lien Representative will deliver to the Junior Lien Purchaser Representative a statement of the amount of Parity Lien Obligations then outstanding. The right to purchase provided for in this paragraph will expire unless, within 15 Business Days after the receipt by the Junior Lien Purchaser Representative of such statements from the applicable Priority Lien Representative and Parity Lien Representative, the Junior Lien Purchaser Representative (i) delivers to the applicable Priority Lien Representative an irrevocable commitment of the Junior Lien Purchasers to purchase all (but not less than all) of the Priority Lien Obligations (including unfunded commitments) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing and (ii) delivers to the applicable Parity Lien Representative an irrevocable commitment of the Junior Lien Purchasers to purchase all (but not less than all) of the Parity Lien Obligations and to otherwise complete the purchase on the terms set forth under this provision.

        On the date specified by the Junior Lien Purchaser Representative (on behalf of the Junior Lien Purchasers) in such irrevocable commitment (which shall not be less than five Business Days, nor more than 20 Business Days, after the receipt by the applicable Priority Lien Representative and Parity Lien Representative of such irrevocable commitment), (x) the holders of the Priority Lien Obligations shall sell to the Junior Lien Purchasers all (but not less than all) Priority Lien Obligations (including unfunded commitments) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations and any loans provided by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing that are outstanding on the date of such sale and (y) the holders of the Parity Lien Obligations shall sell to the Junior Lien Purchasers all (but not less than all) Parity Lien Obligations, subject in each case to any required approval of any court or other regulatory or governmental authority then in effect, if any, and only if on the date of such sale, the applicable Priority Lien Representative receives the following:

(1)

payment, as the purchase price for all Priority Lien Obligations sold in such sale, of an amount equal to the full amount of all Priority Lien Obligations (other than outstanding letters of credit as referred to in the clause (2) of this paragraph) other than any Priority Lien Obligations constituting Excess Priority Lien Obligations and loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing then outstanding (including principal, interest, fees, reasonable attorneys' fees and legal expenses, but excluding contingent indemnification Obligations for which no claim or demand for payment has been made at or prior to such time); provided that in the case of Obligations in respect of Hedging Obligations that are secured by the Priority Liens, the Parity Lien Purchasers shall cause the applicable agreements governing such Hedging Obligations to be assigned and novated or, if such agreements have been terminated, such purchase price shall include an amount equal to the sum of any unpaid amounts then due in respect of such Hedging Obligations, calculated using the market quotation method and after giving effect to any netting arrangements;



(2)

a cash collateral deposit in such amount as the applicable Priority Lien Representative determines is reasonably necessary to secure the payment of any outstanding letters of credit constituting Priority Lien Debt that may become due and payable after such sale (but not in

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any event in an amount greater than one hundred five percent (105%) of the amount then reasonably estimated by the applicable Priority Lien Representative to be the aggregate outstanding amount of such letters of credit at such time), which cash collateral shall be (A) held by the applicable Priority Lien Representative as security solely to reimburse the issuers of such letters of credit that become due and payable after such sale and any fees and expenses incurred in connection with such letters of credit and (B) returned to the Parity Lien Purchaser Representative (except as may otherwise be required by applicable law or any order of any court or other governmental authority) promptly after the expiration or termination from time to time of all payment contingencies affecting such letters of credit; and

(3)

any agreements, documents or instruments which the applicable Priority Lien Representative may reasonably request pursuant to which the Parity Lien Purchaser Representative and the Parity Lien Purchasers in such sale expressly assume and adopt all of the Obligations of the applicable Priority Lien Representative and the holders of the Priority Lien Obligations under the documents providing for the Priority Lien and in connection with loans provided by the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing on and after the date of the purchase and sale and the Parity Lien Purchaser Representative (or any other representative appointed by the holders of a majority in aggregate principal amount of the Parity Lien Obligations owned by the purchasers) becomes a successor agent thereunder; and

and the applicable Parity Lien Representative receives the following:

(4)

payment, as the purchase price for all Parity Lien Obligations sold in such sale, of an amount equal to the full amount of all Parity Lien Obligations (including principal, interest, fees, reasonable attorneys' fees and legal expenses, but excluding contingent indemnification Obligations for which no claim or demand for payment has been made at or prior to such time); and



(5)

any agreements, documents or instruments which the applicable Parity Lien Representative may reasonably request pursuant to which the Junior Lien Purchaser Representative and the Junior Lien Purchasers in such sale expressly assume and adopt all of the Obligations of the applicable Parity Lien Representative and the holders of the Parity Lien Obligations under the documents providing for the Parity Lien.

        The purchase of the Priority Lien Obligations (including unfunded commitments) and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing shall be made on a pro rata basis among the Junior Lien Purchasers giving notice to the applicable Priority Lien Representative of their interest to exercise the purchase option under the Intercreditor Agreement according to each such holder's portion of the Junior Lien Debt owned by the purchasers or as such Junior Lien Purchasers may otherwise agree. Such purchase price and cash collateral shall be remitted by wire transfer in federal funds to such bank account of the applicable Priority Lien Representative as the applicable Priority Lien Representative may designate in writing to the Junior Lien Purchaser Representative for such purpose. Interest shall be calculated to but excluding the Business Day on which such sale occurs if the amounts so paid by the Junior Lien Purchaser Representative and holders of the Junior Lien Debt to the bank account designated by the applicable Priority Lien Representative are received in such bank account prior to 12:00 noon, New York City time, and interest shall be calculated to and including such Business Day if the amounts so paid by the Junior Lien Purchaser Representative and holders of the Junior Lien Debt to the bank account designated by the applicable Priority Lien Representative are received in such bank account later than 12:00 noon, New York City time.

        The purchase of the Parity Lien Obligations shall be made on a pro rata basis among the Junior Lien Purchasers giving notice to the applicable Parity Lien Representative of their interest to exercise

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the purchase option under the Intercreditor Agreement according to each such holder's portion of the Junior Lien Debt owned by the purchasers or as such Junior Lien Purchasers may otherwise agree. Such purchase price shall be remitted by wire transfer in federal funds to such bank account of the applicable Parity Lien Representative as the applicable Parity Lien Representative may designate in writing to the Junior Lien Purchaser Representative for such purpose. Interest shall be calculated to but excluding the Business Day on which such sale occurs if the amounts so paid by the Junior Lien Purchaser Representative and holders of the Junior Lien Debt to the bank account designated by the applicable Parity Lien Representative are received in such bank account prior to 12:00 noon, New York City time, and interest shall be calculated to and including such Business Day if the amounts so paid by the Junior Lien Purchaser Representative and holders of the Junior Lien Debt to the bank account designated by the applicable Parity Lien Representative are received in such bank account later than 12:00 noon, New York City time.

        Such sale shall be expressly made without representation or warranty of any kind by the applicable Priority Lien Representative and the holders of Priority Lien Obligations as to the Priority Lien Obligations, the Collateral or otherwise and without recourse to the applicable Priority Lien Representative and the holders of Priority Lien Obligations, except that the applicable Priority Lien Representative and the holders of Priority Lien Obligations shall represent and warrant severally as to the Priority Lien Obligations (including unfunded commitments) and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing then owing to them: (i) that the applicable Priority Lien Representative and such holders of the Priority Lien Obligations own the Priority Lien Obligations (including unfunded commitments) and any loans provided by any of the Priority Lien Collateral Agent or any holder of Priority Lien Obligations in connection with a DIP Financing; and (ii) the applicable Priority Lien Representative and such holders of the Priority Lien Obligations have the necessary corporate or other governing authority to assign such interests.

        Such sale shall be expressly made without representation or warranty of any kind by the applicable Parity Lien Representative and the holders of Parity Lien Obligations as to the Parity Lien Obligations, the Collateral or otherwise and without recourse to the applicable Parity Lien Representative and the holders of Parity Lien Obligations, except that the applicable Parity Lien Representative and the holders of Parity Lien Obligations shall represent and warrant severally as to the Parity Lien Obligations: (i) that the applicable Parity Lien Representative and such holders of the Parity Lien Obligations own the Parity Lien Obligations and (ii) the applicable Parity Lien Representative and such holders of the Parity Lien Obligations have the necessary corporate or other governing authority to assign such interests.

        After such sale becomes effective, the outstanding letters of credit will remain enforceable against the issuers thereof and will be secured solely by the cash collateral provided pursuant to the preceding clause (2) of this section.

Application of Proceeds

        Prior to the Discharge of Priority Lien Obligations, and regardless of whether an Insolvency or Liquidation Proceeding has been commenced, Collateral or proceeds received in connection with the enforcement or exercise of any rights or remedies with respect to any portion of the Collateral will be applied:

        first, to the payment in full in cash of all Priority Lien Obligations that are not Excess Priority Lien Obligations,

        second, to the payment in full in cash of all Parity Lien Obligations,

        third, to the payment in full in cash of all Junior Lien Obligations,

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        fourth, to the payment in full in cash of all Excess Priority Lien Obligations, and

        fifth, to the Issuers or as otherwise required by applicable law.

        Following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, and regardless of whether an Insolvency or Liquidation Proceeding has been commenced, Collateral or proceeds received in connection with the enforcement or exercise of any rights or remedies with respect to any portion of the Collateral will be applied:

        first, to the payment in full of all Parity Lien Obligations,

        second, to the payment in full of all Junior Lien Obligations,

        third, to the payment in full in cash of all Excess Priority Lien Obligations, and

        fourth, to the Issuers or as otherwise required by applicable law.

Postponement of Subrogation

        The Intercreditor Agreement provides that no payment or distribution to any holder of Priority Lien Obligations pursuant to the provisions of the Intercreditor Agreement shall entitle the Note Collateral Agent, any holder of Parity Lien Obligations, the Junior Lien Collateral Agent or any holder of Junior Lien Obligations to exercise any rights of subrogation in respect thereof until, in the case of the Note Collateral Agent or the holders of Parity Lien Obligations, the Discharge of Priority Lien Obligations, and in the case of the Junior Lien Collateral Agent and the holders of Junior Lien Obligations, the Discharge of Parity Lien Obligations shall have occurred. Following the Discharge of Priority Lien Obligations, each holder of Priority Lien Obligations will execute such documents, agreements, and instruments as any holder of Parity Lien Obligations may reasonably request to evidence the transfer by subrogation to any such Person of an interest in the Priority Lien Obligations resulting from payments or distributions to such holder by such Person, so long as all costs and expenses (including all reasonable legal fees and disbursements) incurred in connection therewith by such holder of Priority Lien Obligations are paid by such Person upon request for payment thereof.

        Following the Discharge of Priority Lien Obligations but prior to the Discharge of Parity Lien Obligations, the Intercreditor Agreement provides that no payment or distribution to any holder of Parity Lien Obligations pursuant to the provisions of the Intercreditor Agreement shall entitle the Junior Lien Collateral Agent or any holders of Junior Lien Obligations to exercise any rights of subrogation in respect thereof. Following the Discharge of Parity Lien Obligations, each holder of Parity Lien Obligations will execute such documents, agreements, and instruments as any holder of Junior Lien Obligations may reasonably request to evidence the transfer by subrogation to any such Person of an interest in the Parity Lien Obligations resulting from payments or distributions to such holder by such Person, so long as all costs and expenses (including all reasonable legal fees and disbursements) incurred in connection therewith by such holder of Parity Lien Obligations are paid by such Person upon request for payment thereof.

Release of Liens in Respect of Notes

        The indenture provides that the Note Collateral Agent's Liens upon the Collateral will no longer secure the notes outstanding under the indenture or any other Obligations under the Note Documents, and the right of the holders to the benefits and proceeds of the Note Collateral Agent's Liens on the Collateral will terminate and be discharged:

(1)

upon satisfaction and discharge of the indenture as set forth under the caption "—Satisfaction and Discharge";

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(2)

upon a Legal Defeasance or Covenant Defeasance of the notes as set forth under the caption "—Legal Defeasance and Covenant Defeasance";



(3)

upon payment in full in cash and discharge of all notes outstanding under the indenture and all other Obligations that are outstanding, due and payable under the indenture and the other Note Documents at the time the notes are paid in full in cash and discharged;



(4)

as to any Collateral of the Issuers or any Guarantor that is sold, transferred or otherwise disposed of by the Issuers or any Guarantor to a Person that is not (either before or after such sale, transfer or disposition) the Issuers or a Restricted Subsidiary of the Company in a transaction or other circumstance that complies with the provisions described in the first paragraph under the caption "—Repurchase at the Option of Holders—Asset Sales" below (other than the obligation to apply proceeds of such Asset Sale as provided in such provision) and is permitted by all of the other Note Documents, at the time of such sale, transfer or other disposition or to the extent of the interest sold, transferred or otherwise disposed of; provided that the Note Collateral Agent's Liens upon the Collateral will not be released if the sale or disposition is subject to the covenant described below under the caption "—Certain Covenants—Merger, Consolidation or Sale of Assets";



(5)

in whole or in part, with the consent of the holders of the requisite percentage of notes in accordance with the provisions described below under the caption "—Amendment, Supplement and Waiver";



(6)

with respect to the assets of any Guarantor, at the time that such Guarantor is released from its Note Guarantee as described above under the caption "—Note Guarantees"; or



(7)

if and to the extent required by the provisions of the Intercreditor Agreement described above in clauses (ii) or (iii) of the first paragraph under the caption "—The Intercreditor Agreement—Automatic Release of Parity and Junior Liens";



(8)

the release of Excess Proceeds that remain unexpanded after the conclusion of an Asset Sale Offer conducted in accordance with the provision described below under the caption "—Asset Sales."

        In addition, the Note Collateral Agent's Liens on the Collateral will be released upon the terms and subject to the conditions set forth in Section 4.01 of the Intercreditor Agreement

Further Assurances; Liens on Additional Property

        The indenture provides that the Issuers and any Guarantors will do or cause to be done all acts and things that may be required, or that the Note Collateral Agent from time to time may reasonably request, to assure and confirm that the Note Collateral Agent holds, for the benefit of the holders of the Parity Lien Obligations, duly created and enforceable and perfected Liens upon the Collateral (including any property or assets constituting Collateral that are acquired or otherwise become, or are required by any Note Document to become, Collateral after the notes are issued), in each case, as contemplated by, and with the Lien priority required under, the Note Documents and in connection with any merger, consolidation or sale of assets of either of the Issuers or any Guarantor, the property and assets of the Person which is consolidated or merged with or into either of the Issuers or any Guarantor, to the extent that they are property or assets of the types which would constitute Collateral under the Note Security Documents, shall be treated as after-acquired property and such Issuer or such Guarantor shall take such action as may be reasonably necessary to cause such property and assets to be made subject to the Parity Liens, in the manner and to the extent required under the Note Security Documents.

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        The Issuers and any Guarantors will promptly execute, acknowledge and deliver such Note Security Documents, instruments, certificates, notices and other documents, and take such other actions as shall be reasonably required, or that the Note Collateral Agent may reasonably request, to create, perfect, protect, assure or enforce the Liens and benefits intended to be conferred, in each case as contemplated by the Note Documents for the benefit of the holders of Parity Lien Obligations; provided that no such Note Security Document, instrument or other document shall be materially more burdensome upon the Issuers and any Guarantors than the Note Documents executed and delivered (or required to be executed and delivered promptly after the date of the indenture) by the Issuers and any Guarantors in connection with the issuance of the notes on or about the date of the indenture.

        In addition, from and after the date of the indenture, if the Issuers or any Guarantor acquires any property or asset that constitutes collateral for the Priority Lien Debt or Junior Lien Debt, and any Priority Lien Document or Junior Lien Document, as applicable, requires any supplemental security document for such collateral or other actions to achieve a perfected Lien on such collateral, then the Issuers shall, or shall cause the applicable Guarantor to, promptly (but not in any event no later than the date that is 20 Business Days after which such supplemental security documents are executed and delivered (or other action taken) under such Priority Lien Documents or Junior Lien Documents, as applicable), to the extent permitted by applicable law, execute and deliver to the Note Collateral Agent appropriate Note Security Documents (or amendments thereto) in such form as shall be necessary to grant the Note Collateral Agent a perfected second-priority Lien on such Collateral (subject only to the Priority Lien and the Permitted Liens) or take such other actions in favor of the Note Collateral Agent as shall be reasonably necessary to grant a perfected Lien on such collateral to the Note Collateral Agent, subject to the terms of the indenture, the Intercreditor Agreement and the other Note Documents. Additionally, subject to the indenture, the Intercreditor Agreement and the other Note Documents, if the Issuers or any Guarantor creates any additional Lien upon any property or asset that would constitute Collateral, or takes any additional actions to perfect any existing Lien on Collateral, in each case for the benefit of the holders of the Priority Lien Debt or the holders of Junior Lien Debt, after the date of the indenture, the Issuers or such Guarantor, as applicable, must, to the extent permitted by applicable law, within 20 Business Days after such Lien is granted or other action taken, grant a second-priority Lien upon such property or asset (subject only to the Priority Lien and the Permitted Liens), or take such additional perfection actions, as applicable, for the benefit of the holders and obtain all related deliverables as those delivered to the Priority Lien Collateral Agent or Junior Lien Collateral Agent, as applicable, in each case as security for the obligations of the Issuers with respect to the notes, the obligations of the Guarantors under the Note Guarantees and the performance of all other obligations of the Issuers and any Guarantors under the Note Documents.

        Notwithstanding the foregoing, to the extent that any Lien on any Collateral is perfected by the possession or control of such Collateral or of any account in which such Collateral is held, and if such Collateral or any such account is in fact in the possession or under the control of the Priority Lien Collateral Agent, or of agents or bailees of the Priority Lien Collateral Agent, the perfection actions and related deliverables described in this paragraph shall not be required.

Trust Indenture Act Not Applicable

        The indenture is not subject to the provisions of Section 314 of the Trust Indenture Act, including any requirements to deliver annual opinions with respect to perfection of security interests or opinions with respect to releases of collateral in accordance with the indenture or the Intercreditor Agreement; provided that the indenture is not required to be qualified under the Trust Indenture Act.

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Optional Redemption

        Except as set forth below, the notes will not be redeemable at the Issuers' option prior to June 1, 2017. The Issuers are not, however, prohibited from acquiring the notes by means other than a redemption, whether pursuant to a tender offer, open market purchase or otherwise.

        At any time prior to June 1, 2017, the Issuers may on any one or more occasions redeem up to 35% of the aggregate principal amount of notes issued under the indenture (including any additional notes issued after the Issue Date), less the amount of notes redeemed pursuant to the previous sentence, at a redemption price of 110% of the principal amount, plus accrued and unpaid interest, if any, to, but not including, the Redemption Date, subject to the right of holders on the relevant record date to receive interest due on the relevant interest payment date occurring on or prior to the Redemption Date, in an amount not greater than the net cash proceeds of one or more Equity Offerings; provided that:

(1)

at least 50% of the aggregate principal amount of notes issued under the indenture (excluding notes held by the Company and its Subsidiaries, including the Co-Issuer) remains outstanding immediately after the occurrence of such redemption; and



(2)

the redemption occurs within 180 days of the date of the closing of such Equity Offering.

        On or after June 1, 2017, the Issuers may redeem all or a part of the notes upon not less than 30 nor more than 60 days' notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest, if any, on the notes redeemed, to, but not including, the applicable Redemption Date, if redeemed during the 12-month period beginning on June 1 of the years indicated below, subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date occurring on or prior to the Redemption Date:

        At any time prior to June 1, 2017, the Issuers may also redeem all or a part of the notes, upon not less than 30 nor more than 60 days' prior notice mailed by first-class mail to each holder's registered address, at a redemption price equal to 100% of the principal amount of notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest, if any, to, but not including, Redemption Date, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date occurring on or prior to the Redemption Date.

        In addition, the notes are subject to redemption as provided below under "—Repurchase at the Option of Holders—Change of Control."

        Unless the Issuers default in the payment of the redemption price, interest will cease to accrue on the notes or portions thereof called for redemption on the applicable Redemption Date.

        Any notice of any redemption may, at the Issuers' discretion, be subject to one or more conditions precedent, including, but not limited to, completion of an Equity Offering or other corporate transaction. If the redemption conditions specified in the redemption notice are not satisfied by the Redemption Date set forth therein, the Issuers may, as specified in the redemption notice, extend the redemption period or withdraw the redemption notice or the redemption notice may be deemed null and void.

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Selection and Notice

        If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption as follows:

(1)

if the notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the notes are listed; or



(2)

if the notes are not listed on any national securities exchange, on a pro rata basis (or, in the case of notes in global form, based on a method as the depository for the notes may require).

        No notes of $2,000 or less can be redeemed in part. Notices of redemption will be given by first class mail at least 30 but not more than 60 days before the Redemption Date to each holder of notes to be redeemed at its registered address (with a copy to the trustee), except that redemption notices may be mailed more than 60 days prior to a Redemption Date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notwithstanding the foregoing, notice to DTC shall be given in accordance with DTC's procedures and not mailed.

        If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption unless redemption is conditioned upon the closing of a specified transaction or other condition precedent. On and after the Redemption Date, interest ceases to accrue on notes or portions of notes called for redemption unless the Issuers default in the payment of the redemption price.

Mandatory Redemption

        The Issuers are not required to make mandatory redemption or sinking fund payments with respect to the notes.

Repurchase at the Option of Holders

Change of Control

        If a Change of Control occurs, each holder of notes will have the right to require the Issuers to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess of $2,000) of that holder's notes pursuant to a Change of Control Offer on the terms set forth in the indenture. In the Change of Control Offer, the Issuers will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased to, but not including, the date of purchase, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date occurring on or prior to the Change of Control Payment Date. Within 30 days following any Change of Control, the Issuers will provide notice to each holder (with a copy to the trustee) describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes on the Change of Control Payment Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is provided, pursuant to the procedures required by the indenture and described in such notice; provided that a Change of Control Offer may be made in advance of a Change of Control, and conditioned upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making the Change of Control Offer. The Issuers will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the

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indenture, the Issuers will comply with the applicable securities laws and regulations and will not be deemed to have breached their obligations under the Change of Control provisions of the indenture by virtue of such compliance.

        On the Change of Control Payment Date, the Issuers will, to the extent lawful:

(1)

accept for payment all notes or portions of notes (in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess of $2,000) properly tendered pursuant to the Change of Control Offer and not properly withdrawn;



(2)

deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes accepted for payment; and



(3)

deliver or cause to be delivered to the trustee the notes properly accepted together with an Officer's Certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Issuers.

        The paying agent will promptly mail to each holder of notes properly tendered the Change of Control Payment for such notes, and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each new note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess of $2,000.

        The provisions described above that require the Issuers to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holders of the notes to require that the Issuers repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

        If holders of not less than 90% in aggregate principal amount of the outstanding notes validly tender and do not withdraw such notes in a Change of Control Offer and the Issuers, or any other Person making a Change of Control Offer in lieu of the Issuers as described above, purchase all of the notes validly tendered and not withdrawn by such holders, the Issuers will have the right, upon not less than 30 nor more than 60 days' prior notice, given not more than 30 days following such purchase pursuant to the Change of Control Offer described above, to redeem all notes that remain outstanding following such purchase at a redemption price in cash equal to the applicable Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest, if any, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

        The Issuers will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Issuers and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the indenture as described above under the caption "—Optional Redemption," unless and until there is a default in payment of the applicable redemption price.

        The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of "all or substantially all" of the properties or assets of the Company and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Issuers to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Company and its Subsidiaries taken as a whole to another Person or group may be uncertain.

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        The provisions under the indenture relative to the Issuers' obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified or terminated with the written consent of the holders of a majority in principal amount of the notes then outstanding (including consents obtained in connection with a tender offer or exchange offer for the notes) prior to the occurrence of such Change of Control.

Asset Sales

        The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1)

the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the Fair Market Value (such Fair Market Value to be determined on the date of contractually agreeing to such Asset Sale) of the assets or Equity Interests issued or sold or otherwise disposed of; and



(2)

at least 75% of the aggregate consideration received from such Asset Sale and all other Asset Sales since the Issue Date, on a cumulative basis, by the Company or such Restricted Subsidiary is in the form of cash, Cash Equivalents or Marketable Securities, or any combination thereof. For purposes of this provision, each of the following will be deemed to be cash:



(a)

any liabilities of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets and as a result of which the Company or such Restricted Subsidiary is released from further liability;



(b)

any securities, notes, other obligations or assets received by the Company or any such Restricted Subsidiary from such transferee that are converted by the Company or such Restricted Subsidiary into cash or Cash Equivalents within 120 days of the receipt thereof, to the extent of the cash or Cash Equivalents received in that conversion;



(c)

any Designated Non-cash Consideration received by the Company or any of its Restricted Subsidiaries in such Asset Sale; provided that the aggregate Fair Market Value of such Designated Non-cash Consideration, taken together with the Fair Market Value at the time of receipt of all other Designated Non-cash Consideration received pursuant to this clause (c) less the amount of Net Proceeds previously realized in cash from prior Designated Non-cash Consideration is less than the greater of (x) 3.5% of ACNTA at the time of the receipt of such Designated Non-cash Consideration (with the Fair Market Value of each item of Designated Non-cash Consideration being measured at the time received and without giving effect to subsequent changes in value), and (y) $35.0 million; and



(d)

any Capital Stock of the kind referred to in clause (2) of the next paragraph of this covenant.

        Within 365 days after the receipt of any Net Proceeds from an Asset Sale, the Company (or the applicable Restricted Subsidiary, as the case may be) may:

(a)

apply such Net Proceeds, at its option:



(1)

to repay, redeem or repurchase Priority Lien Debt and other outstanding Priority Lien Obligations or any Parity Lien Debt (provided that with respect to Parity Lien Debt, such repayment, redemption, or repurchase must be made either by a pro rata redemption or repayment of outstanding Parity Lien Debt or by an offer to purchase on a pro rata basis made to all holders of Parity Lien Debt);

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(2)

to acquire all or substantially all of the assets of, or any Capital Stock of, another Permitted Business; provided that in the case of any such acquisition of Capital Stock, such Person is or becomes a Restricted Subsidiary;



(3)

to make a capital expenditure useful in the Oil and Gas Business;



(4)

to acquire other long-term assets that are not classified as current assets under GAAP and that are used or useful in a Permitted Business;



(5)

to invest in Additional Assets; or



(b)

enter into a binding commitment to apply the Net Proceeds pursuant to clauses (a) (2), (3), (4) or (5) above; provided that such binding commitment shall be treated as a permitted application of the Net Proceeds from the date of such commitment until the earlier of (x) the date on which such acquisition or expenditure is consummated, and (y) the 180th day following the expiration of the aforementioned 365 day period.

        Pending the final application of any Net Proceeds, the Company may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture.

        Any Net Proceeds from Asset Sales that are not applied or invested as provided in the second paragraph of this covenant will constitute "Excess Proceeds." Not later than the 366th day (or such later date as permitted by clause (b) of this covenant) from the later of the date of such Asset Sale or the receipt of such Net Proceeds, if the aggregate amount of Excess Proceeds exceeds $20.0 million, within ten Business Days thereof, the Issuers will make an Asset Sale Offer to all holders of notes issued under the indenture, to purchase the maximum principal amount of notes that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount plus accrued and unpaid interest, if any, to, but excluding, the date of purchase, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company or any Restricted Subsidiary may use such Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the Company shall select the notes to be purchased on a pro rata basis (or, if applicable, the procedures of DTC), on the basis of the aggregate principal amounts (or accreted values) tendered in round denominations (which in the case of the notes will be minimum denominations of $2,000 principal amount or multiples of $1,000 in excess thereof). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero.

        The Issuers will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to a Change of Control Offer or an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control or Asset Sale provisions of the indenture, the Issuers will comply with the applicable securities laws and regulations and will not be deemed to have breached their obligations under the Change of Control or Asset Sale provisions of the indenture by virtue of such compliance.

        The agreements governing the Issuers' other Indebtedness, including the Credit Agreement, contain, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require the Issuers to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on the Issuers. In the event a Change of Control or Asset Sale occurs at a time when the Issuers are prohibited from purchasing notes, the Issuers could seek the consent of their senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such

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prohibition. If the Issuers do not obtain a consent or repay those borrowings, the Issuers will remain prohibited from purchasing notes. In that case, the Issuers' failure to purchase tendered notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under the other indebtedness. Finally, the Issuers' ability to pay cash to the holders of notes upon a repurchase may be limited by the Issuers' then existing financial resources.

Certain Covenants

Covenant Suspension

        During any period of time and beginning on the day that (a) the notes have an Investment Grade Rating and (b) no Default or Event of Default has occurred and is continuing under the indenture, the Company and its Restricted Subsidiaries will not be subject to the provisions of the indenture described under:

(1)

"—Repurchase at the Option of Holders—Asset Sales";



(2)

"—Restricted Payments";



(3)

"—Incurrence of Indebtedness and Issuance of Preferred Equity";



(4)

"—Dividend and Other Payment Restrictions Affecting Subsidiaries";



(5)

"—Designation of Restricted and Unrestricted Subsidiaries";



(6)

"—Transactions with Affiliates";



(7)

clause (4) of the covenant described below under the caption "—Merger, Consolidation or Sale of Assets"; and



(8)

"—Business Activities."

        If the Company and its Restricted Subsidiaries are not subject to these covenants for any period of time as a result of the previous sentence (a "Fall-Away Period") and, subsequently, the ratings assigned to the notes are withdrawn or downgraded so the notes no longer have an Investment Grade Rating or an Event of Default (other than with respect to a suspended covenant) occurs and is continuing, then the Company and its Restricted Subsidiaries will thereafter again be subject to these covenants. The ability of the Company and its Restricted Subsidiaries to make Restricted Payments after the time of such withdrawal, downgrade or Event of Default will be calculated as if the covenant governing Restricted Payments had been in effect during the entire period of time from the Issue Date. Notwithstanding the foregoing, the continued existence after the end of the Fall-Away Period of facts and circumstances or obligations arising from transactions which occurred during a Fall-Away Period shall not constitute a breach of any covenant set forth in the indenture or cause an Event of Default thereunder.

        During the Fall-Away Period, the Issuers may not designate any Subsidiaries as Unrestricted Subsidiaries pursuant to the second sentence of the definition of "Unrestricted Subsidiary."

        There can be no assurance that the notes will ever achieve an Investment Grade Rating or that any such rating will be maintained.

Restricted Payments

        The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1)

declare or pay any dividend or make any other payment or distribution on account of the Company's or any of its Restricted Subsidiaries' Equity Interests (including, without limitation,

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any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company's or any of its Restricted Subsidiaries' Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company and other than dividends or distributions payable to the Company or a Restricted Subsidiary);

(2)

purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company or any direct or indirect parent of the Company;



(3)

make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity or scheduled sinking fund payment, any Existing Notes (including any Permitted Refinancing Indebtedness thereof) or Indebtedness that is contractually subordinated to the notes or any Note Guarantee, except (a) a payment of interest or principal on or after the date when due or within three Business Days prior thereto, or (b) in anticipation of satisfying a sinking fund obligation, principal installment payment or payment due at the Stated Maturity thereof, in each case due within three months of the date of such payment, purchase or other acquisition or (c) payments on Indebtedness owed to the Company or a Guarantor; or



(4)

make any Restricted Investment;

(all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as "Restricted Payments"), unless, at the time of and after giving effect to such Restricted Payment:

(1)

no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;



(2)

the Company would, after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption "—Incurrence of Indebtedness and Issuance of Preferred Equity"; and



(3)

such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries since the Issue Date (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7), (8), (9), (10), (12), (13), (14), (15), (16), (17), (18) and (20) of the next succeeding paragraph), is less than the sum, without duplication, of:



(a)

50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from the Start Date to the end of the Company's most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit); plus



(b)

100% of the aggregate net proceeds, including cash and the Fair Market Value of property other than cash used in the Oil and Gas Business, received by the Company since the Start Date (i) as a contribution to its common equity capital or (ii) from the issue or sale of Equity Interests of the Company or any direct or indirect parent company of the Company (other than Disqualified Stock, Designated Preferred Stock or Excluded Contributions) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities that have been converted into or exchanged

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for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of the Company); plus

(c)

to the extent that any Restricted Investment that was made after the Start Date is sold for cash or otherwise liquidated or repaid for cash, 100% of the aggregate amount received in cash and the Fair Market Value of property other than cash received; plus



(d)

to the extent that any Unrestricted Subsidiary of the Company designated as such after the Start Date is redesignated as a Restricted Subsidiary after the Start Date or has been merged into, consolidated or amalgamated with or into, or transfers or conveys its assets to, the Company or a Restricted Subsidiary, 100% of the Fair Market Value of the Company's Investment in such Subsidiary as of the date of such redesignation, combination or transfer (or of the assets transferred or conveyed, as applicable) after deducting any Indebtedness associated with the Unrestricted Subsidiary so designated or combined or any Indebtedness associated with the assets so transferred or conveyed; plus



(e)

100% of any dividends or distributions received by the Company or a Restricted Subsidiary after the Start Date from an Unrestricted Subsidiary of the Company, to the extent that such dividends or distributions were not otherwise included in the Consolidated Net Income of the Company for such period.

        The preceding provisions will not prohibit:

(1)

the payment of any dividend or distribution or the consummation of any redemption within 60 days after the date of declaration of the dividend or distribution or giving of the redemption notice, as the case may be, if, at the date of declaration or notice, the dividend, distribution or redemption payment would have complied with the provisions of the indenture;



(2)

the making of any Restricted Payment in exchange for, or out of the net cash proceeds received by the Company of the substantially concurrent sale (other than to a Subsidiary of the Company) of, Equity Interests of the Company or any direct or indirect parent company of the Company (other than Disqualified Stock) or from the substantially concurrent contribution of common equity capital to the Company; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will be excluded from clause (3)(b) of the preceding paragraph;



(3)

the repurchase, redemption, defeasance or other acquisition or retirement for value of (i) Existing Notes or (ii) Indebtedness of the Company or any Restricted Subsidiary that is contractually subordinated to the notes or to any Note Guarantee with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness;



(4)

the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary to the holders of its Equity Interests on a pro rata basis;



(5)

the repurchase, redemption or other acquisition or retirement (or dividends or distributions to any direct or indirect parent company of the Company to finance any such repurchase, redemption or other acquisition or retirement) for value of any Equity Interests of the Company or any Restricted Subsidiary or any direct or indirect parent company of the Company held by any current or former officer, director, consultant or employee of the Company or any of its Restricted Subsidiaries or any direct or indirect parent company of the Company pursuant to any equity subscription agreement, stock option agreement, shareholders' or members' agreement or similar agreement, plan or arrangement; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $10.0 million in any calendar year (with unused amounts in any

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calendar year being permitted to be carried over for the two succeeding calendar years); provided further that the amount in any calendar year may be increased by an amount not to exceed:

(a)

the cash proceeds received by the Company or any of its Restricted Subsidiaries from the sale of Equity Interests (other than Disqualified Stock) of the Company or any direct or indirect parent company of the Company (to the extent contributed to the Company) to members of management, directors or consultants of the Company and its Restricted Subsidiaries or any direct or indirect parent company of the Company that occurs after the Issue Date (provided that the amount of such cash proceeds utilized for any such repurchase, retirement, other acquisition, or dividend or distribution will not increase the amount available for Restricted Payments under clause (3) of the immediately preceding paragraph); plus



(b)

the cash proceeds of key man life insurance policies received by the Company or any direct or indirect parent company of the Company (to the extent contributed to the Company) and its Restricted Subsidiaries after the Issue Date;

(provided that the Company may elect to apply all or any portion of the aggregate increase contemplated by clauses (a) and (b) above in any single calendar year);

(6)

the repurchase of Equity Interests deemed to occur upon the exercise of stock options or warrants to the extent such Equity Interests represent a portion of the exercise price of those stock options or warrants;



(7)

the declaration and payment of regularly scheduled or accrued dividends or distributions to holders of any class or series of Disqualified Stock of the Company or any Restricted Subsidiary issued on or after the Issue Date in accordance with the caption "—Incurrence of Indebtedness and Issuance of Preferred Equity";



(8)

Permitted Payments to Parent;



(9)

purchases of receivables pursuant to a Receivables Repurchase Obligation in connection with a Qualified Receivables Financing;



(10)

the declaration and payment of dividends or distributions to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) issued after the Issue Date and the declaration and payment of dividends to any direct or indirect parent company of the Company, the proceeds of which will be used to fund the payment of dividends or distributions to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) of any direct or indirect parent company of the Company issued after the Issue Date; provided, however, that (A) for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date of issuance of such Designated Preferred Stock, after giving effect to such issuance (and the payment of dividends or distributions) on a pro forma basis, the Company could incur an additional $1.00 of Indebtedness pursuant to the Fixed Charge Coverage Ratio, and (B) the aggregate amount of dividends declared and paid pursuant to this clause (10) does not exceed the net cash proceeds actually received by the Company (including any such proceeds contributed to the Company by any direct or indirect parent company of the Company) from any such sale of Designated Preferred Stock (other than Disqualified Stock) issued after the Issue Date;



(11)

[Reserved];



(12)

Restricted Payments in an aggregate amount equal to the amount of Excluded Contributions previously received by the Company and its Restricted Subsidiaries;

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(13)

other Restricted Payments in an aggregate amount not to exceed the greater of (x) $35.0 million and (y) 3.5% of ACNTA since the Start Date;



(14)

the satisfaction of change of control obligations and asset sale obligations once the Company has fulfilled its obligations under the indenture with respect to a Change of Control or an Asset Sale;



(15)

the repayment of intercompany debt that was permitted to be incurred pursuant to clauses (2) and (6) of "—Incurrence of Indebtedness and Issuance of Preferred Equity";



(16)

cash dividends or other distributions on the Company's Capital Stock used to, or the making of loans to any direct or indirect parent of the Company to, fund the payment of fees and expenses owed by the Company or its Restricted Subsidiaries to Affiliates, to the extent permitted by clause (3), (4), (7) or (8) of the covenant described under "—Transactions with Affiliates";



(17)

(a) repurchases or exchanges of Existing Notes on the Issue Date solely in consideration for the issuance of Junior Lien Notes pursuant to the Exchange Agreement and (b) other repurchases and exchanges of up to $25 million in aggregate principal amount of Existing Notes solely in consideration for the issuance of additional Junior Lien Notes in an amount not to exceed $20 million aggregate principal amount of additional Junior Lien Notes at a rate of exchange that is not more favorable to holders of such Existing Notes than the exchange rate for the applicable series of Existing Notes exchanged on the Issue Date pursuant to clause (a) (provided that in the case of clauses (a) and (b), costs, fees and expenses and accrued interest expense may be paid in cash consideration);



(18)

so long as no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof, the payment of dividends or distributions on the Company's common equity (or the payment of dividends or distributions to a direct or indirect parent company of the Company to fund the payment by such parent company of dividends or distributions on its common equity) of up to 6.0% per calendar year of the net proceeds received by the Company from any public Equity Offering or contributed to the Company by a direct or indirect parent company of the Company from any public Equity Offering after the Issue Date; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will be excluded from clause (3)(b) of the preceding paragraph;



(19)

[Reserved]; and



(20)

any Restricted Payment made to fund the declaration and payment of dividends (i) in additional shares of the Mandatorily Convertible Preferred Stock or (ii) by increasing the liquidation preference, in accordance with the terms of the Certificate of Designations, to holders of the Mandatorily Convertible Preferred Stock.

        The amount of all Restricted Payments (other than cash) will be the Fair Market Value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. In the event that a Restricted Payment meets the criteria of more than one of the exceptions described in clauses (1) through (20) above or is entitled to be made pursuant to the first paragraph above, the Company shall, in its sole discretion, be entitled to divide or classify such Restricted Payment (or portion thereof) on the date made or later divide or reclassify such Restricted Payment (or portion thereof) in any manner that complies with this covenant.

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Exchanges of Specified Debt

        The Company will not, and will cause its Restricted Subsidiaries not to, (i) exchange Priority Lien Obligations for Specified Indebtedness or Equity Interests of the Company or any of its Restricted Subsidiaries, (ii) exchangeParity Lien Debt or Junior Lien Debt for Existing Notes (other than as contemplated by clause 17(b) of the Restricted Payment covenant). (iii) redeem, repurchase, defease or otherwise acquire or retire Specified Indebtedness or Equity Interests of the Company or any of its Restricted Subsidiaries with the proceeds of the issuance of Priority Lien Obligations or (iv) redeem, repurchase, defease or otherwise acquire or retire Existing Notes with the proceeds from Junior Lien Debt or the notes.

Incurrence of Indebtedness and Issuance of Preferred Equity

        The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, "incur") any Indebtedness (including Acquired Debt), and the Company will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred equity; provided, however, that the Companymay incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Company, the Co-Issuer or any Guarantor may incur Indebtedness (including Acquired Debt) or issue preferred equity, if on the date thereof the Fixed Charge Coverage Ratio for the Company's most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or such preferred equity is issued, as the case may be, would have been at least 2.25 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the preferred equity had been issued, as the case may be, at the beginning of such four-quarter period.

        The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, "Permitted Debt"):

(1)

the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness under any Credit Facility, provided that the aggregate principal amount of all such Indebtedness outstanding at any time (with outstanding letters of credit being deemed to have a principal amount equal to the stated amount thereof) does not exceed the greatest of (i) $275.0 million, (ii) the Borrowing Base in effect at the time of such incurrence and (iii) 25.0% of Modified ACNTA determined as of the date of such incurrence and after giving effect to the application of the proceeds therefrom;



(2)

the incurrence by the Company or any of its Restricted Subsidiaries of the Existing Notes and other Indebtedness, in each case to the extent outstanding on the Issue Date (after giving effect to the transactions contemplated by the Exchange Agreement) (other than Indebtedness described under clause (1), (3) or (6) of this paragraph);



(3)

(a) the incurrence by the Company and any Guarantors of Indebtedness represented by the notes to be issued on the Issue Date and any related Note Guarantees including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (3)(a) and (b) the incurrence by the Company and any Guarantors of the Junior Lien Notes issued on the Issue Date in an aggregate principal amount of $504.121 million pursuant to the Exchange Agreement and up to $20.0 million of additional Junior Lien Notes incurred as contemplated by clause 17(b) of the covenant described under "—Restricted Payments", in each case, plus accretion of all paid-in-kind interest thereon and any Permitted Refinancing Indebtedness incurred to renew,

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refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (3)(b);

(4)

the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings, industrial revenue bonds, purchase money obligations or other Indebtedness or preferred stock, or synthetic lease obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, development, construction, installation or improvement of property (real or personal and including Capital Stock), plant or equipment used in the business of the Company or any of its Restricted Subsidiaries (in each case, whether through the direct purchase of such assets or the Equity Interests of any Person owning such assets), including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), in an aggregate principal amount not to exceed at any time outstanding the greater of (x) $40.0 million and (y) 1.5% of ACNTA determined as of the date of such incurrence;



(5)

the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clauses (2), (5) or (12) of this paragraph;



(6)

the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:



(a)

if the Company or any Guarantor is the obligor on such Indebtedness and the payee is not an Issuer or a Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of the Issuers, or the Note Guarantee, in the case of a Guarantor; and



(b)

(i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Company or a Restricted Subsidiary, will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);



(7)

the issuance by any of the Company's Restricted Subsidiaries to the Company or to any of its Restricted Subsidiaries of shares of preferred equity; provided, however, that:



(a)

any subsequent issuance or transfer of Equity Interests that results in any such preferred equity being held by a Person other than the Company or a Restricted Subsidiary, and



(b)

any sale or other transfer of any such preferred equity to a Person that is not either the Company or a Restricted Subsidiary,

will be deemed, in each case, to constitute an issuance of such preferred equity by such Restricted Subsidiary that was not permitted by this clause (7);

(8)

the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations other than for speculative purposes and Banking Services Obligations in the ordinary course of business;



(9)

the guarantee by the Company or any of its Restricted Subsidiaries of Indebtedness of the Company or a Restricted Subsidiary that was permitted to be incurred by another provision of

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this covenant (including the first paragraph hereof); provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the notes, then the Guarantee shall be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed;

(10)

the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness in respect of workers' compensation claims, payment obligations in connection with health or other types of social security benefits, unemployment or other insurance or self-insurance obligations, reclamation, statutory obligations, bankers' acceptances, performance, surety or similar bonds and letters of credit or completion or performance guarantees (including without limitation, performance guarantees pursuant to supply agreements or equipment leases), or other similar obligations in the ordinary course of business or consistent with past practice;



(11)

the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds;



(12)

the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness, Disqualified Stock or preferred equity of the Company or any Restricted Subsidiary incurred or issued to finance an acquisition or of Persons that are acquired by the Company or any of its Restricted Subsidiaries or merged into a Restricted Subsidiary in accordance with the terms of the indenture; provided, however, that after giving effect to such acquisition and the incurrence of such Indebtedness, Disqualified Stock and preferred equity either:



(a)

the Company would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first sentence of this covenant; or



(b)

the Fixed Charge Coverage Ratio would not be less than immediately prior to such acquisition;



(13)

Indebtedness incurred by a Receivables Subsidiary in a Qualified Receivables Financing that is not recourse to the Company or any Restricted Subsidiary other than a Receivables Subsidiary (except for Standard Securitization Undertakings);



(14)

the incurrence of Indebtedness arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, adjustment of purchase price, earn outs, or similar obligations, in each case, incurred or assumed in connection with the disposition or acquisition of any business, assets or a Subsidiary in accordance with the terms of the indenture, other than guarantees of Indebtedness incurred or assumed by any Person acquiring all or any portion of such business, assets or Subsidiary for the purpose of financing such acquisition; and



(15)

the incurrence by the Company or any of its Restricted Subsidiaries of additional Indebtedness or the issuance of Disqualified Stock or preferred equity in an aggregate principal amount (or accreted value, as applicable) or having an aggregate liquidation preference at any time outstanding not to exceed the greater of (x) $50.0 million and (y) 3.5% of ACNTA determined as of the date of such incurrence.

        For purposes of determining compliance with this "Incurrence of Indebtedness and Issuance of Preferred Equity" covenant, in the event that an item of proposed Indebtedness, Disqualified Stock or preferred equity meets the criteria of more than one of the categories of Permitted Debt described in clauses (2) through (15) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify such item of Indebtedness, Disqualified Stock or preferred equity on the date of its incurrence and will only be required to include the amount and type of such Indebtedness, Disqualified Stock or preferred equity in one of the above clauses (or

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paragraphs), although the Company may divide and classify an item of Indebtedness, Disqualified Stock or preferred equity in one or more of the types of Indebtedness, Disqualified Stock or preferred equity and may later reclassify all or a portion of such item of Indebtedness, Disqualified Stock or preferred equity, in any manner that complies with this covenant; provided that all Indebtedness outstanding on the Issue Date under the Credit Agreement shall be deemed incurred under clause (1) of the preceding paragraph and any amounts outstanding under any Credit Facility must be incurred under clause (1) and in all such cases may not be reclassified.

        Notwithstanding anything in this indenture to the contrary and without duplication of any other provisions of the indenture, the Issuers shall not and the Restricted Subsidiaries shall not, directly or indirectly, incur, or suffer to exist (a) any Indebtedness (other than the Indebtedness permitted under clause (3) of the definition of "Permitted Debt") that is secured by any Liens that have any form of contractual subordinated Lien priority with respect to the Liens securing any other Indebtedness of the Issuer or any of the Restricted Subsidiaries (other than the Parity Lien Debt and Junior Lien Debt), or (b) any Indebtedness pursuant to clause (1) or (3) secured by a common Lien with other Indebtedness, subject to a payment waterfall or similar arrangement whereby one item of Indebtedness has priority over the other in its right to receive proceeds of Collateral covered by such common Lien, in each case, other than (i) Indebtedness incurred under the Credit Facilities secured by Liens with respect to assets which also secure Indebtedness under clause (4) and Liens securing the Credit Facilities that have a subordinate priority with respect to such Indebtedness under clause (4) to the Liens securing such Indebtedness under clause (4), (ii) Indebtedness of a Person existing at the time such Person becomes a Guarantor that is secured by Liens that are permitted pursuant to clauses (3) and (4) of the definition of the term "Permitted Liens." and (iii) Indebtedness incurred under clause (13) may be secured by a common lien with other Indebtedness incurred under clause (13) and be subject to a waterfall arrangement among such Indebtedness as described in the immediately preceding clause (b).

        The accrual of interest or dividends, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, the reclassification of preferred equity as Indebtedness due to a change in accounting principles, the payment of dividends on Disqualified Stock or preferred equity (including the Mandatorily Convertible Preferred Stock) in the form of additional shares of the same class of Disqualified Stock or preferred equity (including the Mandatorily Convertible Preferred Stock) and unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of ASC-815) will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock or preferred equity (including the Mandatorily Convertible Preferred Stock) for purposes of this covenant; provided, in each such case (other than preferred stock that is not Disqualified Stock, including the Mandatorily Convertible Preferred Stock), that the amount of any such accrual, accretion or payment is included in Fixed Charges of the Company as accrued.

        Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values.

        The amount of any Indebtedness outstanding as of any date will be:

(1)

the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;



(2)

the principal amount of the Indebtedness, in the case of any other Indebtedness; and



(3)

in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:



(a)

the Fair Market Value of such assets at the date of determination; and

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(b)

the amount of the Indebtedness of the other Person.

Liens

        The Company will not, and will not permit any Guarantor to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) on any of their property or assets, now owned or hereafter acquired.

Dividend and Other Payment Restrictions Affecting Subsidiaries

        The Company will not, and will not permit any of its Restricted Subsidiaries (other than the Co-Issuer) that is not a Guarantor to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary (other than the Co-Issuer) that is not a Guarantor to:

(a)

pay dividends or make any other distributions on its Capital Stock to the Company or any of its Restricted Subsidiaries, or with respect to any other interest or participation in, or measured by, its profits, or pay any Indebtedness owed to the Company or any of its Restricted Subsidiaries;



(b)

make loans or advances to the Company or any of its Restricted Subsidiaries; or



(c)

sell, lease or transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries.

        However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1)

agreements governing Indebtedness outstanding on the Issue Date, the Credit Agreement and Credit Facilities and the related documentation and related Hedging Obligations as in effect on the Issue Date and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the Issue Date;



(2)

the indenture, the notes and the Note Guarantees (and any Additional Notes and related guarantees under the indenture);



(3)

applicable law, rule, regulation, order, approval, license, permit or similar restriction;



(4)

any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;



(5)

non-assignment provisions or subletting restrictions in contracts, leases and licenses entered into in the ordinary course of business;



(6)

purchase money obligations for property (including Capital Stock) acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (c) of the preceding paragraph;

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(7)

any agreement for the sale or other disposition of the Capital Stock or assets of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending closing of the sale or other disposition;



(8)

Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;



(9)

Liens permitted to be incurred under the provisions of the covenant described above under the caption "—Liens" that limit the right of the debtor to dispose of the assets securing such Indebtedness;



(10)

provisions limiting the disposition or distribution of assets or property or transfer of Capital Stock in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements, limited liability company organizational documents, and other similar agreements entered into in the ordinary course of business, consistent with past practice or with the approval of the Company's Board of Directors, which limitation is applicable only to the assets, property or Capital Stock that are the subject of such agreements;



(11)

any encumbrance or restriction of a Receivables Subsidiary effected in connection with a Qualified Receivables Financing; provided, however, that such restrictions apply only to such Receivables Subsidiary;



(12)

restrictions on cash, Cash Equivalents, Marketable Securities or other deposits or net worth imposed by customers or lessors under contracts or leases entered into in the ordinary course of business;



(13)

other Indebtedness of Restricted Subsidiaries that are Foreign Subsidiaries that is incurred subsequent to the Issue Date pursuant to the covenant described under "—Incurrence of Indebtedness and Issuance of Preferred Equity";



(14)

encumbrances on property that exist at the time the property was acquired by the Company or a Restricted Subsidiary;



(15)

contractual encumbrances or restrictions in effect on the Issue Date, and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the Issue Date;



(16)

any customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of "Permitted Business Investment";



(17)

any encumbrance or restriction with respect to an Unrestricted Subsidiary pursuant to or by reason of an agreement that the Unrestricted Subsidiary is a party to or entered into before the date on which such Unrestricted Subsidiary became a Restricted Subsidiary; provided that such agreement was not entered into in anticipation of the Unrestricted Subsidiary becoming a Restricted Subsidiary and any such encumbrance or restriction does not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property of such Unrestricted Subsidiary;



(18)

any encumbrance or restriction contained in the terms of any Indebtedness or any agreement pursuant to which such Indebtedness was incurred if either (x) the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant

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in such Indebtedness or agreement or (y) the Company determines that any such encumbrance or restriction will not materially affect the Company's ability to make principal or interest payments on the notes, as determined in good faith by the Board of Directors of the Company, whose determination shall be conclusive;

(19)

provisions with respect to the receipt of a rebate on an operating lease until all obligations due to a lessor on other operating leases are satisfied or other customary restrictions in respect of assets or contract rights acquired by a Restricted Subsidiary in connection with a sale and lease back transaction;



(20)

in the case of clause (c) of the preceding paragraph, any encumbrance or restriction that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease, sublease, license or similar contract (including any agreements or contracts related to Oil and Gas Properties), or the assignment or transfer of any such, license (including without limitations, licenses of intellectual property) or other contracts; and



(21)

any encumbrances or restrictions imposed by any amendments or refinancings of the contracts, instruments or obligations referred to above in clauses (1) through (20); provided that such amendments or refinancings are not materially more restrictive, taken as a whole, than such encumbrances and restrictions prior to such amendment or refinancing.

Merger, Consolidation or Sale of Assets

        The Company will not, directly or indirectly: (1) consolidate or merge with or into another Person; or (2) sell, assign, transfer, convey or otherwise dispose of all or substantially all of its properties or assets (determined on a consolidated basis for the Company and its Restricted Subsidiaries) in one or more related transactions to another Person, unless:

(1)

either (a) the Company is the surviving entity; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, conveyance or other disposition has been made (the "Successor") is a corporation, partnership or limited liability company organized or existing under the laws of the United States, any state of the United States or the District of Columbia;



(2)

the Successor assumes all the obligations of the Company under the notes and the indenture pursuant to a supplemental indenture executed and delivered to the trustee and assumes all obligations of the Company under the Registration Rights Agreement, the Note Security Documents and other Note Documents;



(3)

immediately after such transaction, no Default or Event of Default exists;



(4)

(a) the Company or the Successor would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption "—Incurrence of Indebtedness and Issuance of Preferred Equity" or (b) the Fixed Charge Coverage Ratio for the successor entity and its Restricted Subsidiaries would not be less than such ratio for the Company and its Restricted Subsidiaries immediately prior to such transaction; and



(5)

the Successor shall take such action (or agree to take such action) as may be reasonably necessary to cause any property or assets that constitute Collateral owned by or transferred to the Successor to be subject to the Parity Liens in the manner and to the extent required under the Note Documents; and

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(6)

the Company or the Successor, as applicable, shall have delivered to the Trustee, in form and substance reasonably satisfactory to the Trustee, an Officers' Certificate and Opinion of Counsel stating that such consolidation, merger, transfer, lease or other disposition and any supplemental indenture and other agreements in respect thereto comply with the requirements under the Indenture.

        The Successor in any of the above transactions (if not the Company) will succeed to, and be substituted for the Company under the indenture and the notes and the Company (if not the surviving Person) will be fully released from its obligations under the Indenture and the notes, except in the case of a lease of all or substantially all of its assets.

        Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve "all or substantially all" of the properties or assets of a Person.

        This "Merger, Consolidation or Sale of Assets" covenant does not apply to:

(1)

a merger of the Company with an Affiliate solely for the purpose of reincorporating the Company in another jurisdiction; or



(2)

any consolidation or merger, or any sale, assignment, transfer, conveyance, lease or other disposition of assets between or among the Company and its Restricted Subsidiaries.

Transactions with Affiliates

        The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of the Company (each, an "Affiliate Transaction"), involving aggregate consideration in excess of $2.0 million, unless:

(1)

the Affiliate Transaction is on terms that are not materially less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and



(2)

the Company delivers to the trustee with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $20.0 million, a resolution of the Board of Directors of the Company certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members, if any, of the Board of Directors of the Company.

        The following items will not be deemed to be Affiliate Transactions and, therefore, are not subject to the provisions of the prior paragraph:

(1)

any employment agreement, employee benefit plan, pension plan, officer or director indemnification agreement or any similar arrangement entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business or consistent with past practice and payments pursuant thereto;



(2)

transactions (including a merger) between or among the Company and/or any of its Restricted Subsidiaries;



(3)

transactions with a Person (other than an Unrestricted Subsidiary of the Company) that is an Affiliate of the Company solely because the Company owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;

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(4)

payment of reasonable fees to, and indemnity provided on behalf of, officers, directors, employees or consultants of the Company or any of its Restricted Subsidiaries or any direct or indirect parent company of the Company;



(5)

any issuance of Equity Interests (other than Disqualified Stock) of the Company to Affiliates of the Company or to any director, officer, employee or consultant of the Company or any direct or indirect parent company of the Company, and the granting and performance of registration rights;



(6)

Restricted Payments and Permitted Investments that do not violate the provisions of the indenture described above under the caption "—Restricted Payments," or Permitted Payments to Parent;



(7)

the entering into any agreement to pay, and the payment of, customary annual management, consulting, monitoring and advisory fees to the Equity Investors in an amount not to exceed in any four quarter period $2.5 million;



(8)

loans or advances to employees or consultants in the ordinary course of business or consistent with past practice;



(9)

any transaction effected as part of a Qualified Receivables Financing;



(10)

any transaction in which the Company or any of its Restricted Subsidiaries, as the case may be, delivers to the trustee a letter from an accounting, appraisal or investment banking firm of national standing stating that such transaction is fair to the Company or such Restricted Subsidiary from a financial point of view or that such transaction meets the requirements of clause (1) of the preceding paragraph;



(11)

the existence of, or the performance by the Company or any of its Restricted Subsidiaries of its obligations under the terms of, any acquisition agreements or members' or stockholders agreement or related documents to which it is a party as of the Issue Date and any amendment thereto or similar agreements which it may enter into thereafter; provided, however, that the existence of, or the performance by the Company or any of its Restricted Subsidiaries of its obligations under, any future amendment to any such existing agreement or under any similar agreement entered into after the Issue Date shall only be permitted by this clause (11) to the extent that the terms of any such existing agreement, together with all amendments thereto, taken as a whole, or such new agreement are not otherwise more disadvantageous to the holders of the notes taken as a whole than the original agreement as in effect on the Issue Date;



(12)

transactions with Unrestricted Subsidiaries, customers, clients, suppliers, joint venture partners or purchasers or sellers of goods or services, or lessors or lessees of property, in each case in the ordinary course of business and otherwise in compliance with the terms of the indenture which are, in the aggregate (taking into account all the costs and benefits associated with such transactions), materially no less favorable to the Company or its Restricted Subsidiaries than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person, in the reasonable determination of the Board of Directors of the Company or senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party;



(13)

(a) guarantees of performance by the Company and its Restricted Subsidiaries of Unrestricted Subsidiaries in the ordinary course of business, except for guarantees of Indebtedness in respect of borrowed money, and (b) pledges of Equity Interests of Unrestricted Subsidiaries for the benefit of lenders of Unrestricted Subsidiaries;

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(14)

if such Affiliate Transaction is with a Person in its capacity as a holder of Indebtedness or Capital Stock of the Company or any Restricted Subsidiary where such Person is treated no more favorably than the holders of Indebtedness or Capital Stock of the Company or any Restricted Subsidiary;



(15)

transactions effected pursuant to agreements in effect on the Issue Date and any amendment, modification or replacement of such agreement (so long as such amendment or replacement is not materially more disadvantageous to the holders of the notes, taken as a whole);



(16)

payments to the Equity Investors made for any financial advisory, financing or other investment banking activities, including without limitation, in connection with acquisitions or divestitures, which payments are approved by a majority of the Board of Directors; and



(17)

any sale of oil, natural gas or other Hydrocarbons or other mineral products to an Affiliate of the Company or the entering into or performance of Commodity Agreements, gas gathering, transportation or processing contracts, drilling contracts, operating agreements or oil or natural gas marketing or exchange contracts with an Affiliate of the Company, in each case, in the ordinary course of business, so long as the terms of any such transaction are approved by a majority of the directors of the Board of Directors who are disinterested with respect to such transaction.

Business Activities

        The Company will not, and will not permit any of its Restricted Subsidiaries to, engage in any business other than Permitted Businesses, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

Additional Note Guarantees

        If the Company or any of its Restricted Subsidiaries acquires or creates a Restricted Subsidiary after the Issue Date that is not already a Guarantor and that Restricted Subsidiary (other than the Co-Issuer or any Immaterial Subsidiary that is not a Guarantor under any Credit Facility or any other Indebtedness) (a) guarantees any Indebtedness of the Issuers or any Guarantor under any Credit Facility or (b) if there is no Credit Facility outstanding and in effect at such time, is a Restricted Subsidiary and guarantees any Indebtedness of the Company, then, in either case, that Subsidiary will become a Guarantor by executing a supplemental indenture and delivering an opinion of counsel satisfactory to the trustee within 30 days after the date that Subsidiary was acquired or created or on which it became obligated with respect to such Indebtedness.

Designation of Restricted and Unrestricted Subsidiaries

        The Board of Directors of the Company may designate any Restricted Subsidiary, other than the Co-Issuer, to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary designated as an Unrestricted Subsidiary will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption "—Restricted Payments" or under one or more clauses of the definition of Permitted Investments, as determined by the Company. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

        Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee an Officer's Certificate certifying that such designation complied

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with the preceding conditions and was permitted by the covenant described above under the caption "—Restricted Payments." If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption "—Incurrence of Indebtedness and Issuance of Preferred Equity," the Company will be in default of such covenant. The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) (x) the Company could incur such Indebtedness pursuant to the Fixed Charge Coverage Ratio test described under "—Incurrence of Indebtedness and Issuance of Preferred Equity," or (y) the Fixed Charge Coverage Ratio for the Company and its Restricted Subsidiaries would be greater than such ratio for the Company and its Restricted Subsidiaries immediately prior to such designation, in each case on a pro forma basis taking into account such designation; and (2) no Default or Event of Default would be in existence following such designation.

Payment for Consent

        The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, pay or cause to be paid any cash consideration to or for the benefit of any holder of notes for any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid and is paid to all holders of the notes that are qualified institutional buyers within the meaning of Rule 144A and that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.

Reports

        So long as any of the notes are outstanding, the Company shall file with the SEC, to the extent such submissions are accepted for filing by the SEC, and shall provide to the Trustee (within 15 days after it files (or would have been required to file) with the SEC), all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-K and 10-Q as if the Company were a non-accelerated filer and were required to file such forms; provided that the foregoing delivery requirements shall be deemed satisfied if the required reports are filed for public availability with the SEC or made publicly available on the Company's website.

        In addition, the Issuers and the Guarantors agree that, for so long as any notes remain outstanding, if at any time they are not required to file with the SEC the reports required by the preceding paragraphs, they will furnish to the holders of notes and to prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

        In the event that any direct or indirect parent company of the Company becomes a guarantor of the notes, the indenture permits the Company to satisfy its obligations in this covenant with respect to financial information relating to the Company by furnishing financial information relating to such parent company; provided that the same is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent, on the one hand, and the information relating to the Company and its Subsidiaries on a standalone basis, on the other hand.

        Delivery of such reports, information and documents to the trustee pursuant to the above is for informational purposes only, and the trustee's receipt thereof shall not constitute constructive notice of any information contained therein or determinable from information contained therein, including the

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Issuers' compliance with any of the covenants under the indenture (as to which the trustee is entitled to rely exclusively on an Officer's Certificates).

Events of Default and Remedies

        Each of the following is an "Event of Default":

(1)

default for 30 days in the payment when due of interest on the notes;



(2)

default in the payment when due (at maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;



(3)

failure by the Company or any of its Restricted Subsidiaries for 60 days (or 180 days in the case of a Reporting Failure) after notice to the Company by the trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding voting as a single class to comply with any of the other agreements in the indenture or the Note Security Documents;



(4)

default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any Restricted Subsidiary that is a Significant Subsidiary or group of Restricted Subsidiaries that taken as a whole would constitute a Significant Subsidiary of the Company (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee now exists, or is created after the Issue Date (but excluding Indebtedness owing to the Company or a Restricted Subsidiary), if that default:



(a)

is caused by a failure to pay principal on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness following the Stated Maturity of such Indebtedness (a "Payment Default"); or



(b)

results in the acceleration of such Indebtedness prior to its Stated Maturity, and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $50.0 million or more;



(5)

failure by the Company or any Restricted Subsidiary that is a Significant Subsidiary, or group of Restricted Subsidiaries that taken as a whole would constitute a Significant Subsidiary, to pay final and nonappealable judgments entered by a court or courts of competent jurisdiction aggregating in excess of $50.0 million (net of any amounts which are covered by insurance or bonded), which judgments are not paid, waived, satisfied, discharged or stayed for a period of 60 days;



(6)

except as permitted by the indenture, any Note Guarantee of any Restricted Subsidiary that is a Significant Subsidiary of the Company or any group of Restricted Subsidiaries that taken as a whole would constitute a Significant Subsidiary is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect (other than in accordance with the terms of such Note Guarantee and the indenture), or any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee and such Default continues for ten days;



(7)

certain events of bankruptcy or insolvency described in the indenture with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of the Company's Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary; and

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(8)

the occurrence of the following:



(a)

except as permitted by the Note Documents, any Note Security Document establishing the Parity Liens ceases for any reason to be enforceable other than by reason of the termination of the indenture; provided that it will not be an Event of Default under this clause (8)(a) if the sole result of the failure of one or more Note Security Documents to be fully enforceable is that any Parity Lien purported to be granted under such Note Security Documents on Collateral, individually or in the aggregate, having a Fair Market Value of not more than $15.0 million, ceases to be an enforceable and perfected Parity Lien; provided further that if such failure is susceptible to cure, no Event of Default shall arise with respect thereto until 45 days after any officer of the Company or any Restricted Subsidiary becomes aware of such failure, which failure has not been cured during such time period;



(b)

except as permitted by the Note Documents, any Parity Lien purported to be granted under any Note Security Document on Collateral, individually or in the aggregate, having a Fair Market Value in excess of $15.0 million, ceases to be an enforceable and perfected Parity Lien, subject to the Intercreditor Agreement and Permitted Liens; provided that if such failure is susceptible to cure, no Event of Default shall arise with respect thereto until 45 days after any officer of the Company or any Restricted Subsidiary becomes aware of such failure, which failure has not been cured during such time period; and



(c)

the Company or any Guarantor denies or disaffirms, in writing, any obligation of the Company or any other Guarantor set forth in or arising under any Note Document establishing Parity Liens with respect to Collateral, individually or in aggregate, having a Fair Market Value in excess of $15.0 million; provided that if such written denial or disaffirmation is susceptible to cure, no Event of Default shall arise with respect thereto until 45 days after any officer of the Company or any Restricted Subsidiary becomes aware of such writing, which writing has not been withdrawn or such denial or disaffirmation has not been confirmed or affirmed.

        In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to the Company, the Co-Issuer or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding notes, including all principal and interest and premium, if any, will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all the notes, including all principal, interest and premium, if any, to be due and payable immediately.

        Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal, interest or premium, if any.

        In the event of any Event of Default specified in clause (5) of the first paragraph above, such Event of Default and all consequences thereof (excluding, however, any resulting Payment Default) will be annulled, waived and rescinded, automatically and without any action by the trustee or the holders of the notes, if within 20 days after such Event of Default arose the Issuers deliver an Officer's Certificate to the trustee stating that (x) the Indebtedness or guarantee that is the basis for such Event of Default has been discharged or (y) the holders thereof have rescinded or waived the acceleration, notice or action (as the case may be) giving rise to such Event of Default or (z) the default that is the basis for such Event of Default has been cured, it being understood that in no event shall an acceleration of the principal amount of the notes as described above be annulled, waived or rescinded upon the happening of any such events.

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        In case an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any holders of notes unless such holders have offered to the trustee indemnity or security satisfactory to the trustee against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder of a note may pursue any remedy with respect to the indenture or the notes unless:

(1)

such holder has previously given the trustee notice that an Event of Default is continuing;



(2)

holders of at least 25% in aggregate principal amount of the then outstanding notes have requested the trustee to pursue the remedy;



(3)

such holders have offered the trustee security or indemnity satisfactory to the trustee against any loss, liability or expense;



(4)

the trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and



(5)

holders of a majority in aggregate principal amount of the then outstanding notes have not given the trustee a direction inconsistent with such request within such 60-day period.

        The holders of a majority in aggregate principal amount of the then outstanding notes by notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of interest or premium, if any, on, or the principal of, the notes.

        The Issuers are required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default that has not been cured, the Issuers are required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees, Stockholders and Members

        To the extent permitted by law no director, manager, officer, employee, incorporator, stockholder or member of either of the Company, Co-Issuers, any parent entity of the Company or any Subsidiary, as such, will have any liability for any obligations of the Company, the Co-Issuer or the Guarantors under the notes, the indenture, the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes.

Legal Defeasance and Covenant Defeasance

        The Issuers may at any time, at the option of the Board of Directors evidenced by a resolution set forth in an Officer's Certificate, elect to have all of their obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees ("Legal Defeasance") except for:

(1)

the rights of holders of outstanding notes to receive payments in respect of the principal of, or interest or premium, if any, on, such notes when such payments are due from the trust referred to below;



(2)

the Issuers' obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

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(3)

the rights, powers, trusts, duties and immunities of the trustee or Collateral Agent, and the Issuers' and the Guarantors' obligations in connection therewith; and



(4)

the Legal Defeasance and Covenant Defeasance provisions of the indenture.

        In addition, the Issuers may, at their option and at any time, elect to have the obligations of the Issuers and the Guarantors released with respect to certain covenants (including the obligation to make Change of Control Offers and Asset Sale Offers, their obligations under the covenants described in "—Certain Covenants," and the cross-acceleration provision and judgment default provisions described under "—Events of Default and Remedies") that are described in the indenture ("Covenant Defeasance") and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes.

        In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under "—Events of Default and Remedies" will no longer constitute an Event of Default with respect to the notes.

        In order to exercise either Legal Defeasance or Covenant Defeasance:

(1)

the Issuers must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in such amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, or interest and premium, if any, on, the outstanding notes on the stated date for payment thereof or on the applicable Redemption Date, as the case may be, and the Issuers must specify whether the notes are being defeased to such stated date for payment or to a particular Redemption Date;



(2)

in the case of Legal Defeasance, the Issuers must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee (subject to customary exceptions and exclusions) confirming that (a) the Issuers have received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the Issue Date, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel shall confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;



(3)

in the case of Covenant Defeasance, the Issuers must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee (subject to customary exceptions and exclusions) confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;



(4)

no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit and the grant of any Lien securing such borrowing);



(5)

such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound;



(6)

the Issuers must deliver to the trustee an Officer's Certificate stating that the deposit was not made by the Issuers with the intent of preferring the holders of notes over the other creditors

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of the Issuers with the intent of defeating, hindering, delaying or defrauding any creditors of the Issuers or others; and

(7)

the Issuers must deliver to the trustee an Officer's Certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

        Except as provided in the next two succeeding paragraphs, the Issuers, the Guarantors, the Trustee and the Collateral Agent may amend the indenture (including, without limitation, Sections 4.10 and 4.15 thereof) and the notes or the Note Guarantees, the Intercreditor Agreement and the other Note Documents with the consent of the holders of at least a majority in aggregate principal amount of the then outstanding notes voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing Default or Event of Default or compliance with any provision of the indenture or the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

        Without the consent of each holder of notes affected thereby, an amendment, supplement or waiver will not (with respect to any notes held by a non-consenting holder):

(1)

reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;



(2)

reduce the principal of or extend the fixed maturity of any note or alter the provisions with respect to the redemption of the notes (for the avoidance of doubt, the provisions relating to the covenants described above under the caption "—Repurchase at the Option of Holders" are not redemptions of the notes);



(3)

reduce the rate of or extend the time for payment of interest, including default interest, on any note;



(4)

waive a Default or Event of Default in the payment of principal of, or interest or premium, if any, on, the notes (except a rescission of acceleration of the notes by the holders of at least a majority in aggregate principal amount of the then outstanding notes and a waiver of the Payment Default that resulted from such acceleration);



(5)

make any note payable in money other than that stated in the notes;



(6)

make any change in the provisions of the indenture relating to waivers of past Defaults or impair the rights of holders of notes to receive payments of principal of, or interest or premium, if any, on, the notes;



(7)

waive a redemption payment with respect to any note (for the avoidance of doubt, a payment required by one of the covenants described above under the caption "—Repurchase at the Option of Holders" is not a redemption payment);



(8)

release any Guarantor that is a Significant Subsidiary from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture; or



(9)

make any change in the preceding amendment and waiver provisions.

        In addition, the consent of holders representing at least 66²/3 of outstanding notes will be required to release the Liens for the benefit of the holders of the notes on all or substantially all of the Collateral, other than in accordance with the Note Documents.

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        Notwithstanding the preceding, without the consent of any holder of notes, the Issuers, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:

(1)

to cure any ambiguity, defect or inconsistency;



(2)

to provide for uncertificated notes in addition to or in place of certificated notes;



(3)

to provide for the assumption of the Issuers' or a Guarantor's obligations to holders of notes by a successor to such issuer or such guarantor in the case of a merger or consolidation or sale of all or substantially all of such Issuer's or such Guarantor's assets, as applicable;



(4)

to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any such holder;



(5)

to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;



(6)

(a) to conform the text of the indenture, the Note Guarantees, the Note Documents, the Intercreditor Agreement or the notes to any provision of the Description of Notes to the extent that such provision in the Description of Notes dated May 21, 2015 was intended to be a verbatim recitation of a provision of the indenture, the Note Guarantees, the Note Documents, the Intercreditor Agreement or the notes and (b) to conform the text of the indenture, the Note Guarantees, the Notes Documents, the Intercreditor Agreement or any other such documents (in recordable form) as may be necessary or advisable to preserve and confirm the relative priorities of the Priority Lien Documents, the Note Documents and the Junior Lien Documents as such priorities are contemplated by and set forth in the Intercreditor Agreement;



(7)

to allow any Guarantor to execute a supplemental indenture and/or a Note Guarantee with respect to the notes and to release any Guarantor from a Note Guarantee in accordance with the terms of the indenture;



(8)

to make, complete or confirm any grant of Liens on Collateral permitted or required by the indenture or any of the Note Documents or the Intercreditor Agreement;



(9)

to comply with requirements of any securities depository with respect to the notes;



(10)

to release or subordinate Liens on Collateral in accordance with the Note Security Documents or Intercreditor Agreement; or



(11)

with respect to the Note Security Documents, as provided in the Intercreditor Agreement.

        In addition, the Intercreditor Agreement may be amended, supplemented or otherwise modified in accordance with its terms and without the consent of any holder or the Trustee with the consent of the parties thereto or otherwise in accordance with its terms, including to add additional Indebtedness as Priority Lien Debt, Parity Lien Debt or Junior Lien Debt and add other parties (or any authorized agent thereof or trustee therefor) holding such Indebtedness thereto and to establish that the Liens on any Collateral securing such Indebtedness shall rank equally with the Liens on such Collateral securing the other Priority Lien Debt, Parity Lien Debt or Junior Lien Debt, as applicable, then outstanding, in each case to the extent permitted by the Secured Debt Documents. The Intercreditor Agreement also provides that in certain circumstances the Note Security Documents may be amended automatically without the consent of holders of notes, the Trustee or the Note Collateral Agent in connection with any amendments to corresponding security documents creating Priority Liens.

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        The consent of the holders of the notes is not necessary under the indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment.

Satisfaction and Discharge

        The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when:

(1)

either:



(a)

all notes that have been authenticated and, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust or segregated and held in trust by the Issuers and thereafter repaid to the Issuers, have been delivered to the trustee for cancellation; or



(b)

all notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year or may be called for redemption within one year and the Issuers or any Guarantor have irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness (including all principal and interest) on the notes not delivered to the trustee for cancellation;



(2)

the Issuers or any Guarantor have paid or caused to be paid all other sums payable by them under the indenture; and



(3)

the Issuers have delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the notes at maturity or on the Redemption Date, as the case may be.

        In addition, the Issuers must deliver an Officer's Certificate to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

        The holders of a majority in aggregate principal amount of the then outstanding notes have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care that a prudent person would use under the circumstances in the conduct of his own affairs. The trustee is under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense.

Governing Law

        The indenture, the notes, and the Note Guarantees shall be governed by, and construed in accordance with, the laws of the State of New York.

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Certain Definitions

        Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.

        "Acquired Debt" means, with respect to any specified Person:

(1)

Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Restricted Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and



(2)

Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

        "ACNTA" of the Company means (without duplication), as of the date of determination, the remainder of:

(a)

the sum of:



(i)

discounted future net revenues from Proved Reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company's most recently completed fiscal year, which reserve report is prepared or audited by independent petroleum engineers, as increased by, as of the date of determination, the estimated discounted future net revenues from:



A.

estimated Proved Reserves acquired since such year end, which reserves were not reflected in such year-end reserve report, and



B.

estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves since such year-end due to exploration, development or exploitation, production or other activities, which would, in accordance with standard industry practice, cause such revisions (including the impact to Proved Reserves and future net revenues from estimated development costs incurred and the accretion of discount since such year end),

and decreased by, as of the date of determination, the estimated discounted future net revenues from

C.

estimated Proved Reserves reflected in such reserve report produced or disposed of since such year end, and



D.

reductions in estimated Proved Reserves reflected in such reserve report attributable to downward revisions of estimates of Proved Reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines,

in the case of clauses (A) through (D) utilizing prices and costs calculated in accordance with SEC guidelines as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to the Company were year-end; provided, however, that in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by the Company's petroleum engineers;

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(ii)

the capitalized costs that are attributable to Oil and Gas Properties of the Company and its Restricted Subsidiaries to which no Proved Reserves are attributable, based on the Company's books and records as of a date no earlier than the date of the Company's latest available annual or quarterly financial statements;



(iii)

the Net Working Capital of the Company and its Restricted Subsidiaries on a date no earlier than the date of the Company's latest annual or quarterly financial statements; and



(iv)

the greater of



A.

the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company's latest annual or quarterly financial statements, and



B.

the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company's latest audited financial statements; provided that if no such appraisal has been performed the Company shall not be required to obtain such an appraisal and only clause (iv)(A) of this definition shall apply;

minus

(b)

the sum of (without duplication):



(i)

Minority Interests;



(ii)

any net production or gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company's latest annual or quarterly balance sheet (to the extent not deducted in calculating Net Working Capital of the Company in accordance with clause (a)(iii) above of this definition);



(iii)

to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (but utilizing prices and costs calculated in accordance with SEC guidelines as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to the Company were year-end), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Production Payments and Reserve Sales (determined, if applicable, using the schedules specified with respect thereto); and



(iv)

the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

        If the Company changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, "ACNTA" will continue to be calculated as if the Company were still using the full cost method of accounting.

        "Additional Assets" means:

(1)

any properties or long-term assets to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;

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(2)

capital expenditures useful in the Oil and Gas Business and drilling expenses by the Company or a Restricted Subsidiary in the Oil and Gas Business;



(3)

the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or another Restricted Subsidiary; or



(4)

Capital Stock constituting a Minority Interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

        "Affiliate" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, "control," as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms "controlling," "controlled by" and "under common control with" have correlative meanings.

        "Applicable Premium" means, with respect to any note on any Redemption Date, the greater of:

(1)

1.0% of the principal amount of the note; and



(2)

the excess of:



(a)

the present value at such Redemption Date of (i) the redemption price of the note at June 1, 2017 (such redemption price being set forth in the table appearing above under the caption "—Optional Redemption"), plus (ii) all required interest payments due on the note through June 1, 2017 (excluding accrued but unpaid interest to the applicable Redemption Date), computed using a discount rate equal to the Treasury Rate as of such Redemption Date plus 50 basis points; over



(b)

the principal amount of the note.

        Calculation of the Applicable Premium will be made by the Issuers or on behalf of the Issuers by such person as the Issuers shall designate; provided that such calculation or the correctness thereof shall not be a duty or obligation of the trustee.

        "Asset Acquisition" means:

(1)

an Investment by the Company or any Restricted Subsidiary in any other Person pursuant to which such Person shall become a Restricted Subsidiary, or shall be merged with or into or consolidated with the Company or any Restricted Subsidiary; or



(2)

the acquisition by the Company or any Restricted Subsidiary of the assets of any Person (other than a Restricted Subsidiary) which constitute all or substantially all of the assets of such Person or comprise any division or line of business of such Person or any other properties or assets of such Person other than in the ordinary course of business.

        "Asset Sale" means:

(1)

the sale, lease (including by means of Production Payments and Reserve Sales but excluding an operating lease entered into in the ordinary course of the Oil and Gas Business), conveyance or other disposition of any assets or rights of the Company and its Restricted Subsidiaries not in the ordinary course of business; provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described

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above under the caption "—Repurchase at the Option of Holders—Change of Control" and/or the provisions described above under the caption "—Certain Covenants—Merger, Consolidation or Sale of Assets" and not by the provisions described above under the caption "—Repurchase at the Option of Holders—Asset Sales"; and

(2)

the issuance or sale of Equity Interests in any of the Company's Restricted Subsidiaries (other than Preferred Stock of Restricted Subsidiaries issued in compliance with the covenant described under "—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Equity" and directors' qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary).

        Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

(1)

any single transaction or series of related transactions that involves assets or Equity Interests of any Restricted Subsidiary having a Fair Market Value of less than $20.0 million;



(2)

a transfer of assets between or among the Company and any of its Restricted Subsidiaries;



(3)

an issuance or sale of Equity Interests by a Restricted Subsidiary to the Company or to another Restricted Subsidiary;



(4)

the sale or lease of inventory, products or services or the lease, assignment or sub-lease of any real or personal property;



(5)

the sale or discounting of accounts receivable in the ordinary course of business;



(6)

any sale or other disposition of damaged, worn-out, obsolete or no longer useful assets or properties;



(7)

any sale of assets received by the Company or any of its Restricted Subsidiaries upon the foreclosure on a Lien;



(8)

the sale or other disposition of cash, Cash Equivalents or Marketable Securities;



(9)

a sale of accounts receivable and related assets of the type specified in the definition of "Receivables Financing" to a Receivables Subsidiary in a Qualified Receivables Financing;



(10)

a transfer of accounts receivable and related assets of the type specified in the definition of "Receivables Financing" (or a fractional undivided interest therein) by a Receivables Subsidiary in a Qualified Receivables Financing;



(11)

a Restricted Payment that does not violate the covenant described above under the caption "—Certain Covenants—Restricted Payments" or a Permitted Investment;



(12)

any sale of Equity Interests in, or Indebtedness or other securities of, an Unrestricted Subsidiary;



(13)

the granting of Liens not otherwise prohibited by the indenture;



(14)

the surrender, or waiver of contract rights, oil and gas leases, or settlement, release or surrender of contract, tort or other claims;



(15)

any exchange of assets related to a Permitted Business of comparable market value, as determined in good faith by the Company;



(16)

a disposition of Hydrocarbons or mineral products inventory in the ordinary course of business;



(17)

any Production Payments and Reserve Sales conveyed pursuant to any incentive compensation programs for geologists, geophysicists and other providers of technical services to the

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Company or a Restricted Subsidiary; provided that (i) any such Production Payments and Reserve Sales are on terms that are consistent with the Company's past practices and reasonably customary in the Oil and Gas Business and (ii) the aggregate royalties conveyed pursuant thereto shall not exceed 3%;

(18)

a disposition of Oil and Gas Properties in connection with tax credit transactions complying with Section 29 or any successor or analogous provisions of the Code;



(19)

the abandonment, farmout, lease or sublease of developed or undeveloped Oil and Gas Properties in the ordinary course of business or which are usual and customary in the Oil and Gas Business generally or in the geographic region in which such activities occur;



(20)

[Reserved];



(21)

any financing transaction with respect to property built or acquired by the Company or any Restricted Subsidiary after the Issue Date, including sale and lease back transactions and asset securitizations permitted by the indenture; and



(22)

the early termination or unwinding of any Hedging Obligations.

        In the event that a transaction (or any portion thereof) meets the criteria of a permitted Asset Sale and would also be a permitted Restricted Payment or Permitted Investment, the Company, in its sole discretion, will be entitled to divide and classify such transaction (or any portion thereof) as an Asset Sale and/or one or more of the types of permitted Restricted Payments or Permitted Investments.

        "Asset Sale Offer" has the meaning assigned to that term in the indenture governing the notes.

        "Banking Services" means each and any of the following bank services provided to the Company or any Guarantor by any holder of Priority Lien Debt or any Affiliate thereof: (a) commercial credit or debit cards, (b) stored value cards and (c) Treasury Management Arrangements (including controlled disbursement, automated clearinghouse transactions, return items, overdrafts and interstate depository network services).

        "Banking Services Obligations" means any and all obligations of the Company or any Guarantor, whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor) in connection with Banking Services.

        "Beneficial Owner" has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular "person" (as that term is used in Section 13(d)(3) of the Exchange Act), such "person" will be deemed to have beneficial ownership of all securities that such "person" has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms "Beneficially Owns" and "Beneficially Owned" have a corresponding meaning.

        "Board of Directors" means:

(1)

with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;



(2)

with respect to a partnership, the Board of Directors or other governing body of the general partner of the partnership;

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(3)

with respect to a limited liability company, the Board of Directors or other governing body, and in the absence of same, the manager or board of managers or the managing member or members or any controlling committee thereof; and



(4)

with respect to any other Person, the board or committee of such Person serving a similar function.

        "Borrowing Base" means, with respect to borrowings under the Credit Agreement and any Refinancing Credit Agreement, the maximum amount in United States dollars determined or redetermined by the lenders (who, for the avoidance of doubt, must be (i) commercial bank lenders, (ii) investment banks, (iii) Affiliates of Persons described in the foregoing clauses (i) and (ii), which, in each case, regularly participate in reserve based credit facilities) under the Credit Agreement or any Refinancing Credit Agreement as the aggregate lending value to be ascribed to the Oil and Gas Properties of the Company and its Restricted Subsidiaries against which such lenders are prepared to provide loans or other Indebtedness to the Company and its Restricted Subsidiaries under the Credit Agreement or any Refinancing Credit Agreement, using their customary practices and standards for determining borrowing base loans and which are generally applied to borrowers in the Oil and Gas Business, as determined semi-annually during each year and/or on such other occasions as may be required by the Credit Agreement or any Refinancing Credit Agreement, and which is based upon, inter alia, the review by such lenders of the Hydrocarbon reserves, royalty interests and assets and liabilities of the Company and its Restricted Subsidiaries; provided that such amount shall not exceed $350 million in aggregate principal amount.

        "Business Day" means a day other than a Saturday, Sunday or other day on which banking institutions are authorized or required by law to close in New York State or place of payment.

        "Capital Lease Obligation" means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet (excluding the footnotes thereto) prepared in accordance with GAAP; provided that any obligations of the Company or its Restricted Subsidiaries, or of a special purpose or other entity not consolidated with the Company and its Restricted Subsidiaries, either existing on the Issue Date or created prior to any recharacterization described below (or any refinancing thereof) (i) that were not included on the consolidated balance sheet of the Company as capital lease obligations and (ii) that are subsequently recharacterized as capital lease obligations or, in the case of such a special purpose or other entity becoming consolidated with the Company and its Restricted Subsidiaries, in all such cases due to a change in accounting treatment, shall for all purposes not be treated as a Capital Lease Obligation or Indebtedness.

        "Capital Stock" means:

(1)

in the case of a corporation, corporate stock;



(2)

in the case of an association or business entity that is not a corporation, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;



(3)

in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and



(4)

any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

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        "Cash Equivalents" means:

(1)

United States dollars or, in the case of any Foreign Subsidiary that is a Restricted Subsidiary, such local currencies held by it from time to time in the ordinary course of business;



(2)

securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than one year from the date of acquisition;



(3)

certificates of deposit, time deposits and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers' acceptances with maturities not exceeding one year and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of "B" or better;



(4)

repurchase obligations for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;



(5)

commercial paper having one of the two highest ratings obtainable from Moody's or S&P and, in each case, maturing within one year after the date of acquisition;



(6)

securities issued or fully guaranteed by any state or commonwealth of the United States, or by any political subdivision or taxing authority thereof having one of the two highest ratings obtainable from Moody's or S&P, and, in each case, maturing within one year after the date of acquisition;



(7)

money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition; and



(8)

Indebtedness or Preferred Stock issued by Persons with a rating of "A" or higher from S&P or "A-2" from Moody's with maturities of 24 months or less from the date of acquisition.

        "Certificate of Designations" means the certificate of designations of the Company establishing the voting powers, designations, preferences, limitations, restrictions and relative rights of the Mandatorily Convertible Preferred Stock as in effect on the Issue Date.

        "Change of Control" means the occurrence of any of the following:

(1)

the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company and its Subsidiaries taken as a whole to any "person" (as that term is used in Section 13(d) of the Exchange Act), other than the Permitted Holders; or



(2)

the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any "person" (as defined above), other than the Permitted Holders, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Company or 50% of the aggregate economic interest in the Company, in each case, other than any merger or consolidation as a result of which the holders of a majority of the Company's Voting Stock (measured by voting power rather than number of shares) and such economic interest immediately prior to such transaction continue to own at least a majority of the Voting Stock (measured by voting power rather than number of shares) and such economic interest of the Person surviving or resulting from such transaction or any parent thereof.

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        Notwithstanding the preceding, a conversion of the Company or any of its Restricted Subsidiaries from a limited liability company, corporation, limited partnership or other form of entity to a limited liability company, corporation, limited partnership or other form of entity or an exchange of all of the outstanding Capital Stock in one form of entity for Capital Stock for another form of entity shall not constitute a Change of Control, so long as following such conversion or exchange the "persons" (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of the Company immediately prior to such transactions continue to Beneficially Own in the aggregate more than 50% of the Voting Stock and economic interest of such entity, or continue to own more than 50% of the economic interest and Beneficially Own sufficient Equity Interests in such entity to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such entity, and, in either case no "person" Beneficially Owns more than 50% of the Voting Stock or 50% of the economic interest of such entity.

        "Change of Control Offer" has the meaning assigned to that term in the indenture governing the notes.

        "Change of Control Payment" has the meaning assigned to that term in the indenture governing the notes.

        "Change of Control Payment Date" has the meaning assigned to that term in the indenture governing the notes.

        "Code" means the Internal Revenue Code of 1986, as amended.

        "Collateral" means all property wherever located and whether now owned or at any time acquired after the date of the indenture by the Company or any Guarantor as to which a Lien is granted, or purported to be granted, under the Note Security Documents to secure the notes or any Note Guarantee. "Commodity Agreements" means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement, cap or collar contract, hedging contract or other derivative contract or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

        "Consolidated Cash Flow" means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period (A) plus, without duplication to the extent the same was deducted in calculating Consolidated Net Income:

(1)

provision for taxes based on income, profits or capital, including without limitation state, franchise and similar taxes, of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus



(2)

the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus



(3)

depreciation, depletion, amortization (including amortization of goodwill and other intangibles, deferred financing fees and any amortization included in pension, OPEB or other employee benefit expenses, but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash expenses (including without limitation write-downs and impairment of property, plant, equipment and intangibles and other long-lived assets (including pursuant to the application of ASC-350 and ASC-360) and the impact of purchase accounting, but excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period

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to the extent that such depreciation, depletion, amortization and other non-cash expenses were deducted in computing such Consolidated Net Income; plus

(4)

the amount of any restructuring charges (which, for the avoidance of doubt, shall include retention, severance, integration, business optimization, systems establishment cost or excess pension, OPEB, curtailment or other excess charges); plus



(5)

the minority interest expense consisting of subsidiary income attributable to minority equity interests of third parties in any non-Wholly Owned Restricted Subsidiary in such period or any prior period, except to the extent of dividends declared or paid on Equity Interests held by third parties; plus



(6)

the amount of management, consulting, monitoring and advisory fees and related expenses paid to the Equity Investors or any other Permitted Holder (or any accruals related to such fees and related expenses) during such period; provided that such amount shall not exceed in any four quarter period $2.5 million; plus



(7)

accretion of asset retirement obligations in accordance with ASC-410 and any similar accounting in prior periods; minus

        (B)(1) non-cash items increasing such Consolidated Net Income for such period, other than accruals of revenue in the ordinary course of business or any items which represent the reversal of any accrual of, or cash reserve for, anticipated charges in any prior period where such accrual or reserve is no longer required; and (2) the minority interest income consisting of subsidiary losses attributable to the minority equity interests of third parties in any non-Wholly Owned Restricted Subsidiary.

        "Consolidated Net Income" means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:

(1)

any net after-tax extraordinary, unusual or nonrecurring gains or losses (less all fees and expenses relating thereto) or income or expense or charge (including, without limitation, income, expenses and charges from litigation and arbitration settlements, severance, relocation and other restructuring costs), including, without limitation, any severance or relocation expense, and fees, expenses or charges related to any offering of Equity Interests of such Person, any Investment, acquisition or incurrence or repayment of Indebtedness (in each case, whether or not successful), including all fees, expenses and charges, in each case shall be excluded;



(2)

any net after-tax income or loss from disposed, abandoned, transferred, closed or discontinued operations and any net after-tax gain or loss on disposal of disposed, abandoned, transferred, closed or discontinued operations shall be excluded;



(3)

any net after-tax gains or losses (less all fees and expenses or charges relating thereto) attributable to business dispositions or asset dispositions other than in the ordinary course of business (as determined in good faith by the Company) shall be excluded;



(4)

any net after-tax income or loss (less all fees and expenses or charges relating thereto) attributable to the early extinguishment of indebtedness and Hedging Obligations or other derivative instruments shall be excluded;



(5)

(A) the Net Income for such period of any Person that is not a Subsidiary, or that is an Unrestricted Subsidiary, or that is accounted for by the equity method of accounting, shall be included only to the extent of the amount of dividends or distributions or other payments in respect of equity that are actually paid in cash (or to the extent converted into cash) by the referent Person to the Company or a Restricted Subsidiary thereof in respect of such period

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and (B) the Net Income for such period shall include any dividend, distribution or other payments in respect of equity paid in cash by such Person to the Company or a Restricted Subsidiary thereof in excess of the amount included in clause (A);

(6)

any increase in depreciation, accretion, depletion or amortization or any one-time non-cash charges (such as purchased in-process research and development or capitalized manufacturing profit in inventory) resulting from purchase accounting in connection with any acquisition that is consummated prior to or after the Issue Date shall be excluded;



(7)

accruals and reserves that are established within 12 months after an acquisition's closing date and that are so required to be established as a result of such transaction in accordance with GAAP or as a result of a modification of accounting policies shall be excluded;



(8)

any impairment charges, including those resulting from the application of ASC-350 or ASC-360, and the amortization of intangibles, including those pursuant to ASC-805, or asset write-offs and write-downs shall be excluded;



(9)

any long-term incentive plan accruals and any non-cash compensation expense, including non-cash expenses realized from grants of restricted stock, stock appreciation or similar rights, stock options or other rights to officers, directors and employees of such Person or any of its Restricted Subsidiaries shall be excluded;



(10)

any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines shall be excluded;



(11)

(A) any unrealized non-cash gains or losses or charges in respects of Hedging Obligations (including those resulting from the application of ASC-815), (B) any foreign exchange gains and losses and (C) any adjustments for financial instruments, derivatives or Hedging Obligations required by GAAP shall be excluded except for any realized exchange gains or losses on derivative instruments which are included as offsets to operating items as part of a designated hedging relationship shall be excluded;



(12)

solely for the purpose of determining the amount available for Restricted Payments under clause (3)(a) of the first paragraph of "—Certain Covenants—Restricted Payments," the Net Income of any Restricted Subsidiary (other than the Co-Issuer) that is not a Guarantor will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders or members, unless such restriction with respect to the payment of dividends or similar distributions has been legally waived; provided that Consolidated Net Income of such Person shall be increased by the amount of dividends or distributions or other payments that are actually paid in cash (or to the extent converted into cash) by such Person to the Company or another Restricted Subsidiary thereof in respect of such period, to the extent not already included therein; and



(13)

the cumulative effect of a change in accounting principles will be excluded.

        "Contingent Obligations" means, with respect to any Person, any obligation of such Person guaranteeing any leases, dividends or other obligations that do not constitute Indebtedness ("primary obligations") of any other Person in any manner, whether directly or indirectly, including, without limitation, any obligation of such Person, whether or not contingent:

(1)

to purchase any such primary obligation or any property constituting direct or indirect security thereof,

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(2)

to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor; or



(3)

to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such obligation against loss in respect thereof.

        "continuing" means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.

        "Credit Agreement" means that certain second amended and restated credit agreement, as amended, dated as of June 8, 2012, as further amended on or prior to the Issue Date, by and among the Issuers, SunTrust Bank as administrative agent, and the other lenders party thereto from time to time, providing for revolving credit borrowings and letters of credit, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as amended, restated, modified or renewed from time to time, and as refunded, refinanced or replaced with a reserves based conforming credit facility providing for revolving credit borrowings and letters of credit from lenders (who, for the avoidance of doubt, must be (i) commercial bank lenders, (ii) investment banks, (iii) Affiliates of Persons described in the foregoing clauses (i) and (ii), which, in each case, regularly participate in reserve based credit facilities) (such refinancing or replacement credit facility, a "Refinancing Credit Agreement").

        "Credit Facilities" means one or more debt facilities (including, without limitation, the Credit Agreement and any Refinancing Credit Agreement), with banks or other institutional lenders or investors providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, as amended, restated, modified, renewed, refunded, replaced (whether upon or after termination or otherwise) or refinanced in whole or in part from time to time, including any agreement extending the maturity thereof or otherwise restructuring all or any portion of the indebtedness thereunder or increasing the amount loaned thereunder or altering the maturity thereof.

        "Credit Facility Agent" means, at any time, the Person serving at such time as the "Agent" or "Administrative Agent" under any Credit Facility or any other representative then most recently designated in accordance with the applicable provisions of any Credit Facility, together with its successors in such capacity.

        "Currency Agreement" means any foreign exchange contract, currency swap agreement, currency futures contract, currency option agreement or other similar agreement intended to manage exposure to fluctuations in currency exchange rates.

        "Default" means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

        "Designated Non-cash Consideration" means the Fair Market Value of non-cash consideration that is useful in the Oil and Gas Business received by the Company or one of its Restricted Subsidiaries in connection with an Asset Sale that is so designated as "Designated Non-cash Consideration" pursuant to an Officer's Certificate, setting forth the basis of such valuation, less the amount of cash or Cash Equivalents received in connection with a subsequent sale of such Designated Non-cash Consideration.

        "Designated Preferred Stock" means Preferred Stock of the Company or any direct or indirect parent company of the Company (other than Disqualified Stock) that is issued for cash (other than to the Company or any of its Subsidiaries or an employee stock ownership plan or trust established by the Company or any of its Subsidiaries) and is so designated as Designated Preferred Stock, pursuant to an Officer's Certificate, on the issuance date thereof, the cash proceeds of which are excluded from the

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calculation set forth in clause (3)(b) of the covenant described under "—Certain Covenants—Restricted Payments."

        "Discharge of Parity Lien Obligations" means the occurrence of all of the following:

(1)

payment in full in cash of the principal of and interest, premium (if any) and fees on all Parity Lien Debt; and



(2)

payment in full in cash of all other Parity Lien Obligations that are outstanding and unpaid at the time the Parity Lien Debt is paid in full in cash (other than any obligations for taxes, costs, indemnifications, reimbursements, damages and other liabilities in respect of which no claim or demand for payment has been made at or prior to such time);

provided that, if at any time after the Discharge of Parity Lien Obligations has occurred, the Issuers or any Guarantor enters into any Parity Lien Document evidencing a Parity Lien Obligation which incurrence is not prohibited by the applicable Secured Debt Documents, then such Discharge of Parity Lien Obligations shall automatically be deemed not to have occurred for all purposes of the Intercreditor Agreement with respect to such new Parity Lien Obligations (other than with respect to any actions taken as a result of the occurrence of such first Discharge of Parity Lien Obligations), and, from and after the date on which the Company designates such Indebtedness as Parity Lien Debt in accordance with the Intercreditor Agreement, the obligations under such Parity Lien Document shall automatically and without any further action be treated as Parity Lien Obligations for all purposes of this Agreement, including for purposes of the Lien priorities and rights in respect of Collateral set forth in the Intercreditor Agreement, any Junior Lien Obligations shall be deemed to have been at all times Junior Lien Obligations and at no time Parity Lien Obligations.

        "Discharge of Priority Lien Obligations" means the occurrence of all of the following:

(1)

termination or expiration of all commitments to extend credit that would constitute Priority Lien Debt;



(2)

payment in full in cash of the principal of and interest, premium (if any) and fees on all Priority Lien Debt (other than any undrawn letters of credit);



(3)

discharge or cash collateralization (at 103% of the aggregate undrawn amount of all outstanding letters of credit constituting Priority Lien Debt;



(4)

payment in full in cash of obligations in respect of Hedging Obligations that are secured by the Priority Liens (and, with respect to any particular Hedging Obligation, termination of such agreement and payment in full in cash of all obligations thereunder or such other arrangements as have been made by the counterparty thereto (and communicated to the Priority Lien Collateral Agent)); and



(5)

payment in full in cash of all other Priority Lien Obligations (including Banking Services Obligations) that are outstanding and unpaid at the time the Priority Lien Debt is paid in full in cash (other than any obligations for taxes, costs, indemnifications, reimbursements, damages and other liabilities in respect of which no claim or demand for payment has been made at or prior to such time);

provided that, if, at any time after the Discharge of Priority Lien Obligations has occurred, the Company or any Guarantor enters into any Priority Lien Document evidencing a Priority Lien Debt which incurrence is not prohibited by the applicable Secured Debt Documents, then such Discharge of Priority Lien Obligations shall automatically be deemed not to have occurred for all purposes of the Intercreditor Agreement with respect to such new Priority Lien Debt (other than with respect to any actions taken as a result of the occurrence of such first Discharge of Priority Lien Obligations), and, from and after the date on which the Company designates such Indebtedness as Priority Lien Debt in

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accordance with the Intercreditor Agreement, the obligations under such Priority Lien Document shall automatically and without any further action be treated as Priority Lien Obligations for all purposes of the Intercreditor Agreement, including for purposes of the Lien priorities and rights in respect of Collateral set forth in the Intercreditor Agreement and any Parity Lien Obligations shall be deemed to have been at all times Parity Lien Obligations and at no time Priority Lien Obligations and any Junior Lien Obligations shall be deemed to have been at all times Junior Lien Obligations and at no time Priority Lien Obligations or Parity Lien Obligations.

        "Disqualified Stock" means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock will not constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or an asset sale. The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that the Company and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

        "Dollar-Denominated Production Payments" means production payment Obligations recorded as liabilities in accordance with GAAP, together with all undertakings and Obligations in connection therewith.

        "Domestic Subsidiary" means any Restricted Subsidiary that was formed under the laws of the United States or any state of the United States or the District of Columbia.

        "Equity Interests" means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

        "Equity Investors" means (i) each of First Reserve Fund XII, L.P., FR Midstates Interholding LP, and the Stockholders (as defined in the Stockholders' Agreement, dated as of April 24, 2012, by and among the Company, FR Midstates Interholding LP, and the stockholders party thereto) and their respective Affiliates and (ii) each of Eagle Energy Production, LLC and Riverstone Holdings LLC and their respective Affiliates.

        "Equity Offering" means (i) any public or private sale of Capital Stock (other than Disqualified Stock) of the Company or (ii) any cash contribution to the equity capital of the Company other than public offerings on Form S-4 or S-8 or issuances to a Subsidiary of the Company.

        "Excess Priority Lien Obligations" means Obligations constituting Priority Lien Obligations for the principal amount of loans, letters of credit and reimbursement Obligations under the Credit Agreement and/or any other Credit Facility pursuant to which Priority Lien Debt has been incurred to the extent that such Obligations for principal, letters of credit and reimbursement Obligations are in excess of the Priority Lien Cap.

        "Exchange Act" means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

        "Exchange Agreement" means the Exchange Agreement, dated the Issue Date, by and among the Company and the holders listed on Schedule I thereto pursuant to which the Junior Lien Notes will be issued.

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        "Excluded Contributions" means the net cash proceeds received by the Company after the Issue Date from:

(1)

contributions to its common equity capital, and



(2)

the sale (other than to a Subsidiary of the Company) of Capital Stock (other than Disqualified Stock and Designated Preferred Stock) of the Company,

in each case designated as "Excluded Contributions" pursuant to an Officer's Certificate executed by an Officer of the Company, the net cash proceeds of which are excluded from the calculation set forth in clause (3)(b) of "—Restricted Payments."

        "Existing Notes" means the Issuers' 10.75% Senior Notes due 2020 and 9.25% Senior Notes due 2021, in each case that are outstanding on the Issue Date, as any of the foregoing may be amended, modified or refinanced.

        "Fair Market Value" means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party.

        "Fixed Charge Coverage Ratio" means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than (i) ordinary working capital borrowings and (ii) in the case of revolving credit borrowings or revolving advances under any Qualified Receivables Financing, in which case interest expense will be computed based upon the average daily balance of such Indebtedness during the applicable period, irrespective of when incurred, assumed, guaranteed, repaid, repurchased, redeemed, defeased or otherwise discharged during such period) or issues, repurchases or redeems preferred equity subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the "Calculation Date"), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred equity, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.

        In addition, for purposes of calculating the Fixed Charge Coverage Ratio, Asset Acquisitions, dispositions, mergers, consolidations and discontinued operations (as determined in accordance with GAAP), and any related financing transactions, that the specified Person or any of its Restricted Subsidiaries has both determined to make and made after the Issue Date and during the four-quarter reference period or subsequent to such reference period and on or prior to or simultaneously with the Calculation Date shall be calculated on a pro forma basis assuming that all such Asset Acquisitions, dispositions, mergers, consolidations and discontinued operations (and the change of any associated Fixed Charges and the change in Consolidated Cash Flow resulting therefrom) had occurred on the first day of the four-quarter reference period, including any pro forma expense and cost reductions and other operating improvements that have occurred or are reasonably expected to occur, in the reasonable judgment of the chief financial officer of the Company (regardless of whether these cost savings or operating improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X promulgated under the Securities Act or any other regulation or policy of the SEC related thereto). Any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period, and if, since the beginning of the four-quarter reference period, any Person that subsequently became a Restricted Subsidiary or was merged with or into the Company or any of its other Restricted Subsidiaries since the beginning of such period shall have made any acquisition, Investment, disposition, merger,

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consolidation or discontinued operation, in each case with respect to an operating unit of a business, that would have required adjustment pursuant to this definition, then the Fixed Charge Coverage Ratio shall be adjusted giving pro forma effect thereto for such period as if such Asset Acquisition, disposition, discontinued operation, merger or consolidation had occurred at the beginning of the applicable four-quarter reference period. Any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period.

        For purposes of this definition, whenever pro forma effect is to be given to any transaction, the pro forma calculations shall be made in good faith by a responsible financial or accounting officer of the Company. If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest on such Indebtedness shall be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligations applicable to such Indebtedness if such Hedging Obligation has a remaining term in excess of 12 months). Interest on a Capital Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by a responsible financial or accounting officer of the Company to be the rate of interest implicit in such Capital Lease Obligation in accordance with GAAP. For purposes of making the computation referred to above, interest on any Indebtedness under a revolving credit facility computed on a pro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company may designate. Any such pro forma calculation may include adjustments appropriate, in the reasonable determination of the Company as set forth in an Officer's Certificate, to reflect operating expense reductions reasonably expected to result from any acquisition or merger.

        "Fixed Charges" means, with respect to any specified Person for any period, the sum, without duplication, of:

(1)

the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued, excluding amortization of deferred financing fees, debt issuance costs and commissions, fees and expenses and the expensing of any bridge, commitment or other financing fees, commissions, discounts, yield and other fees and charges (including any interest expense) related to any receivables facility but including original issue discount, non-cash interest payments, the interest component of any deferred payment obligations (classified as Indebtedness under the indenture), the interest component of all payments associated with Capital Lease Obligations and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus



(2)

the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus



(3)

all cash dividend payments or other cash distributions on any series of preferred equity of a Restricted Subsidiary of such Person and all other cash dividend payments or other cash distributions on the Disqualified Stock and Designated Preferred Stock of such Person; less



(4)

interest income; less



(5)

non-cash interest expense attributable to movement in mark to market valuation of Hedging Obligations or other derivatives under GAAP; less



(6)

accretion or accrual of discounted liabilities not constituting Indebtedness; less

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(7)

any expense resulting from the discounting of Indebtedness in connection with the application of purchase accounting in connection with any acquisition; and less



(8)

to the extent not included above, any interest attributable to Dollar-Denominated Production Payments.

        "Foreign Subsidiary" means any Restricted Subsidiary that is organized or existing under the laws of a jurisdiction other than the United States of America or any state thereof or the District of Columbia.

        "GAAP" means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect on the Issue Date.

        "Guarantee" means a guarantee, other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner, including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise).

        "Guarantors" means any Subsidiary of the Company that executes a Note Guarantee in accordance with the provisions of the indenture, and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.

        "Hedging Obligations" means, with respect to any specified Person, the obligations of such Person under Interest Rate Agreements, Currency Agreements or Commodity Agreements.

        "Hydrocarbon Interests" means leasehold and other interests in or under oil, gas and other liquid or gaseous hydrocarbon leases with respect to Oil and Gas wherever located, mineral fee interests, overriding royalty and royalty interests, net profit interests, production payment interests relating to Oil and Gas wherever located, including any beneficial, reserved or residual interest of whatever nature.

        "Hydrocarbons" means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons, petroleum and all constituents, elements or compounds thereof and products refined or processed therefrom.

        "Immaterial Subsidiary" means, at any date of determination, any Restricted Subsidiary whose total assets as of the last day of the most recently ended four fiscal quarter period for which financial statements have been delivered on or prior to such determination date were less than 2.5% of ACNTA; provided, that all Immaterial Subsidiaries shall not in the aggregate have total assets as of the last day of the most recently ended four fiscal quarter period for which financial statements have been delivered on or prior to such determination date greater than 5.0% of ACNTA.

        "Indebtedness" means, with respect to any specified Person, any indebtedness of such Person, whether or not contingent:

(1)

in respect of borrowed money;



(2)

evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);



(3)

in respect of banker's acceptances;



(4)

representing Capital Lease Obligations;

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(5)

representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed;



(6)

to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time); or



(7)

to the extent not otherwise included, with respect to the Company and its Restricted Subsidiaries, the amount then outstanding (i.e., advanced, and received by, and available for use by, the Company or any of its Restricted Subsidiaries) under any Receivables Financing (as set forth in the books and records of the Company or any Restricted Subsidiary and confirmed by the agent, trustee or other representative of the institution or group providing such Receivables Financing);

if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term "Indebtedness" includes (i) all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person); provided, however, that the amount of such Indebtedness shall be the lesser of (x) the Fair Market Value of such asset as such date of determination and (y) the amount of such Indebtedness of such other Person; and (ii) to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person.

        Notwithstanding the foregoing, "Indebtedness" shall not include (a) accrued expenses, royalties and trade payables; (b) Contingent Obligations incurred in the ordinary course of business; (c) asset retirement obligations and obligations in respect of reclamation and workers' compensation (including pensions and retiree medical care) that are not overdue by more than 90 days; (d) Production Payments and Reserve Sales; (e) any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property; (f) any obligations under Currency Agreements, Commodity Agreements and Interest Rate Agreements; provided that such Agreements are entered into for bona fide hedging purposes of the Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of Currency Agreements or Commodity Agreements, such Currency Agreements or Commodity Agreements are related to business transactions of the Company or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of Interest Rate Agreements, such Interest Rate Agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of the Company or its Restricted Subsidiaries incurred without violation of the indenture; or (g) in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business.

        "Initial Junior Lien Indebtedness" means Indebtedness secured by a Junior Lien for which certain requirements of the Intercreditor Agreement have been satisfied that was permitted to be incurred and so secured under each applicable Secured Debt Document, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time in accordance with the applicable Secured Debt Documents.

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        "Initial Junior Lien Trustee" means, at any time, the Person serving at such time as the "Trustee" or "trustee" under the Initial Junior Lien Indebtedness or any other representative then most recently designated in accordance with the applicable provisions of the Initial Junior Lien Indebtedness, together with its successors in such capacity.

        "Insolvency or Liquidation Proceeding" means:

(a)

any case commenced by or against the Company or any Guarantor under the Bankruptcy Code or any other Bankruptcy Law, any other proceeding for the reorganization, recapitalization or adjustment or marshalling of the assets or liabilities of Company or any Guarantor, any receivership or assignment for the benefit of creditors relating to Company or any Guarantor or any similar case or proceeding relative to Company or any Guarantor or its creditors, as such, in each case whether or not voluntary;



(b)

any liquidation, dissolution, marshalling of assets or liabilities or other winding up of or relating to Company or any Guarantor, in each case whether or not voluntary and whether or not involving bankruptcy or insolvency; or



(c)

any other proceeding of any type or nature in which substantially all claims of creditors of Company or any Guarantor are determined and any payment or distribution is or may be made on account of such claims.

        "Intercreditor Agreement" means the Intercreditor Agreement among the Note Collateral Agent, the Priority Lien Collateral Agent and the Junior Lien Collateral Agent, to be entered into on the date of the indenture, as it may be amended, restated, supplemented or otherwise modified from time to time.

        "Interest Rate Agreement" means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

        "Investment Grade Rating" means a Moody's rating of Baa3 (or the equivalent) or higher and an S&P rating of BBB– (or the equivalent) or higher, or, if either such Rating Agency ceases to rate the notes for reasons outside of the Company's control, the equivalent investment grade credit rating from any other Rating Agency.

        "Investment Grade Securities" means:

(1)

securities issued or directly and fully guaranteed or insured by the U.S. government or any agency or instrumentality thereof (other than Cash Equivalents) and in each case with maturities not exceeding two years from the date of acquisition;



(2)

investments in any fund that invests exclusively in investments of the type described in clause (1) which fund may also hold immaterial amounts of cash pending investment and/or distribution; and



(3)

corresponding instruments in countries other than the United States customarily utilized for high quality investments and in each case with maturities not exceeding two years from the date of acquisition.

        "Investments" means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding accounts receivable, trade credit and advances to customers and commission, travel and similar advances to officers, employees and consultants made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity

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Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP.

        "Issue Date" means May 21, 2015.

        "Junior Lien" means a Lien, junior to the Priority Liens and junior to the Parity Liens as provided in the Intercreditor Agreement, granted by any Issuer or any Guarantor in favor of holders of Junior Lien Debt (or any collateral agent or representative in connection therewith), at any time, upon any Property of any Issuer or any Guarantor to secure Junior Lien Obligations.

        "Junior Lien Collateral" shall mean all "collateral," as defined in any Junior Lien Document, and any other assets of any Grantor now or at any time hereafter subject to Liens which secure, but only to the extent securing, any Junior Lien Obligations.

        "Junior Lien Collateral Agent" means (a) Wilmington Trust, National Association as the Junior Lien collateral agent under the Junior Lien Security Documents, together with its successors in such capacity or (b) in the case of any Permitted Refinancing Indebtedness constituting Junior Lien Debt, the collateral agent or representative of the holders of such Junior Lien Debt who maintains the transfer register for such Junior Lien Debt and is appointed as a representative of the Junior Lien Debt (for purposes related to administration of the security documents) pursuant to the indenture, credit agreement or other agreement governing such Junior Lien Debt.

        "Junior Lien Debt" means the Indebtedness incurred under clause (3)(b) of the definition of "Permitted Debt" secured by a Junior Lien.

        "Junior Lien Documents" means, collectively, any indenture, credit agreement or other agreement or instrument pursuant to which Junior Lien Debt is incurred, the documents pursuant to which Junior Lien Obligations are granted and the Junior Lien Security Documents, in each case, as amended, modified, renewed, restated or replaced, in whole or in part, from time to time.

        "Junior Lien Notes" means Third Lien Senior Secured Notes due 2020 to be issued on the Issue Date.

        "Junior Lien Obligations" means Junior Lien Debt and all other Obligations in respect thereof.

        "Junior Lien Representative" means (a) the Initial Junior Lien Trustee, together with its successors in such capacity or (b) in the case of any Permitted Refinancing Indebtedness constituting Junior Lien Debt, the trustee, agent or representative of the holders of such Junior Lien Debt who maintains the transfer register for such Junior Lien Debt and is appointed as a representative of the Junior Lien Debt (for purposes related to administration of the security documents) pursuant to the indenture, credit agreement or other agreement governing such Junior Lien Debt.

        "Junior Lien Security Documents" means all security agreements, pledge agreements, collateral assignments, mortgages, deeds of trust, collateral trust or collateral agency agreements, control agreements or other grants or transfers for security executed and delivered by any Issuer or any Guarantor creating (or purporting to create) a Lien upon Collateral in favor of the Junior Lien Collateral Agent, in each case, as amended, modified, renewed, restated or replaced, in whole or in part, from time to time.

        "Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction.

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        "Mandatorily Convertible Preferred Stock" means the 325,000 shares of $1,000 liquidation preference series A mandatorily convertible preferred stock, par value $0.01 per share, of the Company, authorized by the Certificate of Designations.

        "Marketable Securities" means, with respect to any Asset Sale, any readily marketable equity securities that are (i) traded on The New York Stock Exchange, the American Stock Exchange or the Nasdaq National Market; and (ii) issued by a corporation having a total equity market capitalization of not less than $250.0 million; provided that the excess of (A) the aggregate amount of securities of any one such corporation held by the Company and any Restricted Subsidiary over (B) ten times the average daily trading volume of such securities during the 20 immediately preceding trading days shall be deemed not to be Marketable Securities, as determined on the date of the contract relating to such Asset Sale.

        "Minority Interest" means the percentage interest represented by any class of Capital Stock of a Restricted Subsidiary that is not owned by the Company or a Restricted Subsidiary.

        "Moody's" means Moody's Investors Service, Inc. and its successors and assigns.

        "Modified ACNTA" means, as of any date of determination, an amount equal to the Company's ACNTA calculated as of a date not more than 30 days prior to the date of determination (the "calculation date"), on the following basis:

(1)

in lieu of commodity pricing of future net revenues based on SEC guidelines, Modified ACNTA Prices shall be used after giving effect to all commodity derivatives contracts in effect as of the date of determination as determined in good faith by the Company,



(2)

such calculation shall be based on then current estimates of costs determined in good faith by the Company in light of prevailing market conditions,



(3)

any assets or liabilities relevant to such calculation of Restricted Subsidiaries that are not Guarantors shall be disregarded in such calculation, and



(4)

Net Working Capital will be calculated without including net cash proceeds of the notes.

        "Modified ACNTA Prices" means, as of any date of determination, the forward month prices for the most comparable hydrocarbon commodity applicable to such future production month for a five year period (or such shorter period if forward month prices are not quoted for a reasonably comparable hydrocarbon commodity for the full five year period), with such prices held constant thereafter based on the last quoted forward month price of such period, as such prices are (i) quoted on the NYMEX (or its successor) as of the calculation date (as defined in the definition of Modified ACNTA) and (ii) adjusted for energy content, quality and basis differentials; provided that with respect to estimated future production for which prices are defined, within the meaning of SEC guidelines, by contractual arrangements excluding escalations based upon future conditions, then such contract prices shall be applied to future production subject to such arrangements.

        "Mortgages" means all mortgages, deeds of trust and similar documents, instruments and agreements (and all amendments, modifications and supplements thereof) creating, evidencing, perfecting or otherwise establishing the Liens on Oil and Gas Properties and other related assets to secure Parity Lien Obligations, including payment of the notes and the Note Guarantees or any part thereof.

        "Net Income" means, with respect to any Person for any period, the net income (loss) of such Person for such period, determined in accordance with GAAP and before any reduction in respect of dividends on preferred interests, excluding, however, (a) any gain or loss, together with any related provision for taxes on such gain or loss, realized in connection with (1) any Asset Sale (including, without limitation, dispositions pursuant to Production Payments and Reserve Sales and sale and

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leaseback transactions) or (2) the disposition of any securities by such Person or any of its Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Subsidiaries and (b) any extraordinary or nonrecurring gain or loss, together with any related provision for taxes on such extraordinary or nonrecurring gain or loss.

        "Net Proceeds" means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any Designated Non-cash Consideration received in any Asset Sale and any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise, but only as and when received, but excluding the assumption by the acquiring Person of Indebtedness relating to the disposed assets or other consideration received in any non-cash form), net of the direct costs relating to such Asset Sale and the sale of such Designated Non-cash Consideration, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements, amounts paid in connection with the termination of Hedging Obligations related to Indebtedness repaid with Net Proceeds or hedging oil, natural gas and natural gas liquid production in notional volumes corresponding to the Oil and Gas Properties subject of such Asset Sale, and amounts required to be applied to the repayment of Indebtedness secured by a Lien on the asset or assets that were the subject of such Asset Sale, all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures or to holders of royalty or similar interests as a result of such Asset Sale and any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP, including without limitation, pension and post-employment benefit liabilities and liabilities related to environmental matters or against any indemnification obligations associated with such transaction

        "Net Working Capital" means (a) all current assets of the Company and its Restricted Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities (i) associated with asset retirement obligations relating to Oil and Gas Properties, (ii) included in Indebtedness and (iii) any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

        "Non-Recourse Debt" means Indebtedness:

(1)

as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) other than a pledge of the Equity Interests of any Unrestricted Subsidiaries, (b) is directly or indirectly liable (as a guarantor or otherwise) other than by virtue of a pledge of the Equity Interests of any Unrestricted Subsidiaries, or (c) constitutes the lender; and



(2)

no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit, upon notice, lapse of time or both, any holder of any other Indebtedness (other than the notes offered hereby) of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity.

        "Note Collateral Agent" means (a) Wilmington Trust, National Association, in its capacity as "Collateral Agent" or "Parity Lien Collateral Agent" under the Indenture, the Intercreditor Agreement and the Note Security Documents, and any successor thereto in such capacity or (b) in the case of Permitted Refinancing Indebtedness that constitutes Parity Lien Debt, the collateral agent or

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representative of the holders of such Parity Lien Debt who maintains the transfer register for such Parity Lien Debt and is appointed as a representative of the Parity Lien Debt (for purposes related to administration of the security documents) pursuant to the indenture, credit agreement or other agreement governing such Parity Lien Debt.

        "Note Documents" means the indenture, the notes and the Note Security Documents.

        "Note Guarantee" means the Guarantee by each Guarantor of the Issuers' obligations under the indenture and the notes, executed pursuant to the provisions of the indenture.

        "Note Security Documents" means all security agreements, pledge agreements, collateral assignments, mortgages, deeds of trust, collateral agency agreements, control agreements or other grants or transfers for security executed and delivered by any Issuer or any Guarantor creating (or purporting to create) a Lien upon Collateral in favor of the Notes Collateral Agent, in each case, as amended, modified, renewed, restated or replaced, in whole or in part, from time to time, in accordance with its terms.

        "Obligations" means any principal, premium, if any, interest, penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts (including interest, penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts incurred, whether incurred before or after commencement of an Insolvency or Liquidation Proceeding, and whether or not allowable in an Insolvency or Liquidation Proceeding) payable under the documentation governing any Indebtedness or in respect thereto.

        "Officer" means, with respect to any Person, the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, the Treasurer, any Assistant Treasurer, the Controller, the Secretary or any Vice-President of such Person.

        "Officer's Certificate" means a certificate signed on behalf of the Company or the Issuers (as applicable) by an Officer of the Company or the Issuers (as applicable).

        "Oil and Gas Business" means:

(1)

the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, natural gas liquids and other Hydrocarbons and mineral properties or products produced in association with any of the foregoing;



(2)

the business of gathering, marketing, distributing, treating, processing (but not refining), storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other Hydrocarbons and minerals obtained from unrelated Persons;



(3)

any other related energy business, including power generation and electrical transmission business, directly or indirectly, from oil, natural gas and other Hydrocarbons and minerals produced substantially from properties in which the Company or its Restricted Subsidiaries, directly or indirectly, participate;



(4)

any business relating to oil field sales and service; and



(5)

any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (1) through (4) of this definition.

        "Oil and Gas" means petroleum, natural gas and other related hydrocarbons or minerals or any of them and all other substances produced or extracted in association therewith.

        "Oil and Gas Properties" means Hydrocarbon Interests now owned or hereafter acquired by Issuers or any Subsidiary and contracts executed in connection therewith and all tenements, hereditaments,

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appurtenances, and properties belonging, affixed or incidental to such Hydrocarbon Interests, including, without limitation, any and all property, real or personal, now owned or hereafter acquired by Issuers or any Subsidiary and situated upon or to be situated upon, and used, built for use, or useful in connection with the operating, working or developing of such Hydrocarbon Interests, including, without limitation, any and all petroleum and/or natural gas wells, structures, field separators, processing plants, liquid extractors, plant compressors, pumps, pumping units, field gathering systems, tank and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, liters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, taping, tubing and rods, surface leases, rights-of-way, easements and servitudes, and all additions, substitutions, replacements for, fixtures and attachments to any and all of the foregoing owned directly or indirectly by Issuers or any Subsidiary.

        "Parity Lien" means a Lien, junior to the Priority Liens and senior to the Junior Liens as provided in the Intercreditor Agreement, granted by any Issuer or any Guarantor in favor of the Note Collateral Agent pursuant to a Note Security Document, at any time, upon any Property of any Issuer or any Guarantor to secure Parity Lien Obligations.

        "Parity Lien Debt" means the notes and any related Note Guarantees.

        "Parity Lien Obligations" means Parity Lien Debt and all other Obligations in respect thereof.

        "Parity Lien Purchaser Representative" means a representative of the holders of the notes, selected to act on their behalf in connection with a purchase option by holders of a majority of principal amount of notes held by holders participating in such purchase option.

        "Permitted Business" means the Oil and Gas Business, the businesses of the Company and its Subsidiaries engaged in on the Issue Date and any other activities that are similar, ancillary or reasonably related to, or a reasonable extension, expansion or development of, such businesses or ancillary thereto.

        "Permitted Business Investment" means any Investment or expenditure made in the ordinary course of business or which are of a nature that is or shall have become customary in, the Oil and Gas Business generally or in the geographic region in which such activities occur, including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing or transporting oil, natural gas or other Hydrocarbons and minerals through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1)

Investments in ownership interests in oil, natural gas, other Hydrocarbons and minerals properties, liquefied natural gas facilities, processing facilities, gathering systems, pipelines, storage facilities or related systems or ancillary real property interests;



(2)

Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil, natural gas, other Hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties; and



(3)

Investments in direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment;

provided that "Permitted Business Investments" shall exclude Investments in publicly traded Persons.

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        "Permitted Holders" means the Equity Investors and Related Parties. Any person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the indenture will thereafter, together with its Affiliates, constitute an additional Permitted Holder.

        "Permitted Investments" means:

(1)

any Investment in the Company or in a Restricted Subsidiary;



(2)

any Investment in cash, Cash Equivalents, Marketable Securities or Investment Grade Securities;



(3)

any Investment by the Company or any Restricted Subsidiary in a Person, if as a result of such Investment:



(a)

such Person becomes a Restricted Subsidiary; or



(b)

such Person, in one transaction or a series of related transactions, is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or a Restricted Subsidiary;

and, in each case, any Investment held by any such Person at the time of such transaction, provided such Investment was not made in contemplation of such transaction;

(4)

any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption "—Repurchase at the Option of Holders—Asset Sales";



(5)

any acquisition of assets or Capital Stock solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company or a direct or indirect parent of the Company;



(6)

any Investments received (i) in compromise or resolution of (A) obligations of trade creditors or customers that were incurred in the ordinary course of business of the Company or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (B) litigation, arbitration or other disputes; or (ii) as a result of a foreclosure by the Company or any of its Restricted Subsidiaries with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;



(7)

Investments represented by Hedging Obligations;



(8)

loans or advances to officers, directors and employees made in the ordinary course of business or consistent with the past practice of the Company or any Restricted Subsidiary;



(9)

repurchases of the notes;



(10)

Investments in Permitted Businesses, joint ventures or Unrestricted Subsidiaries having an aggregate Fair Market Value, taken together with all other Investments made pursuant to this clause (10) that are at that time outstanding, not to exceed $15.0 million;



(11)

any Investment in a Receivables Subsidiary or any Investment by a Receivables Subsidiary in any other Person in connection with a Qualified Receivables Financing, including Investments of funds held in accounts permitted or required by the arrangements governing such Qualified Receivables Financing or any related Indebtedness; provided, however, that any Investment in a Receivables Subsidiary is in the form of a Purchase Money Note, contribution of additional receivables or an equity interest;

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(12)

any transaction to the extent it constitutes an Investment that is permitted by and made in accordance with clauses (1), (2), (3), (4), (5), (7), (9), (11), (15) and (16) of the second paragraph of the covenant described under "—Certain Covenants—Transaction with Affiliates";



(13)

(A) Guarantees issued in accordance with the covenants described under "—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Equity" and "—Certain Covenants—Additional Note Guarantees" and (B) Guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating and related agreements and licenses, concessions or operating leases related to the Oil and Gas Business;



(14)

any Investment existing on the Issue Date and any Investment that replaces, refinances or refunds an existing Investment; provided that the new Investment is in an amount that does not exceed the amount replaced, refinanced or refunded, and is made in the same Person as the Investment replaced, refinanced or refunded;



(15)

Investments consisting of purchases and acquisitions of inventory, supplies, materials and equipment or purchases of contract rights or licenses or leases of intellectual property, in each case in the ordinary course of business;



(16)

Permitted Business Investments; and



(17)

additional Investments by the Company or any Restricted Subsidiary having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), taken together with all other Investments made pursuant to this clause (17) that are at the time outstanding not to exceed the greater of (x) $25.0 million and (y) 2.0% of ACNTA;

provided, however, that with respect to any Investment, the Company may, in its sole discretion, allocate all or any portion of any Investment to one or more of the above clauses (1) through (17) so that the entire Investment would be a Permitted Investment.

        "Permitted Liens" means:

(1)

Liens securing Priority Lien Debt incurred under clause (1) of the definition of "Permitted Debt" and Liens securing Hedging Obligations and Banking Services Obligations related thereto;



(2)

Liens in favor of the Company or any of its Restricted Subsidiaries;



(3)

Liens on property of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Subsidiary of the Company; provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any assets other than those of the Person merged into or consolidated with the Company or the Subsidiary;



(4)

Liens on property (including Capital Stock) existing at the time of acquisition of the property by the Company or any Subsidiary of the Company; provided that such Liens were in existence prior to, such acquisition, and not incurred in contemplation of, such acquisition;



(5)

Liens or deposits to secure the performance of statutory or regulatory obligations, or surety, appeal, indemnity or performance bonds, warranty and contractual requirements or other obligations of a like nature incurred in the ordinary course of business and Liens over cash deposits in connection with an acquisition, lease, disposition or investment;

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(6)

Liens securing reimbursement obligations with respect to commercial letters of credit which encumber documents and other assets relating to such letters of credit and products and proceeds thereof and any cash cover relating to a letter of credit or bank guarantee;



(7)

Liens to secure Indebtedness (including Capital Lease Obligations) permitted to be incurred pursuant to clause (4) of the definition of Permitted Debt covering only the assets acquired with or financed by such Indebtedness;



(8)

[Reserved];



(9)

Liens existing on the Issue Date;



(10)

Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded; provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;



(11)

Liens incurred or deposits made in the ordinary course of business to secure payment of workers' compensation or to participate in any fund in connection with workmen's compensation, unemployment insurance, old-age pensions or other social security programs;



(12)

Liens imposed by law, such as carriers', warehousemen's, landlord's, lessor's, suppliers, banks, repairmen's and mechanics' Liens, and Liens of landlords securing obligations to pay lease payments that are not yet due and payable or in default, in each case, incurred in the ordinary course of business;



(13)

leases or subleases granted to others that do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;



(14)

easements, rights of way, zoning and similar restrictions, reservations (including severances, leases or reservations of oil, gas, coal, minerals or water rights), restrictions or encumbrances in respect of real property or title defects that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties (as such properties are used by the Company or its Subsidiaries) or materially impair their use in the operation of the business of the Company and its Subsidiaries;



(15)

(a) Liens created for the benefit of (or to secure) the notes (or the related note guarantees), incurred under clause (3)(a) of the definition of "Permitted Debt" and (b) Liens securing the Junior Lien Notes (and the related note guarantee) incurred under clause (3)(b) of the definition of "Permitted Debt" so long as such Liens constitute Junior Liens;



(16)

Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the indenture; provided, however, that:



(a)

the Indebtedness to be refinanced was previously secured as permitted under the indenture;



(b)

the new Lien has no greater contractual priority relative to the notes or the Note Guarantees;



(c)

the Liens are subject to the terms of the Intercreditor Agreement, if applicable;



(d)

the new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

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(e)

the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;



(17)

Liens arising from precautionary Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business;



(18)

judgment Liens not giving rise to an Event of Default so long as any appropriate legal proceedings that may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such legal proceedings may be initiated shall not have expired;



(19)

Liens securing Indebtedness or other obligations of the Company or any Subsidiary of the Company with respect to Obligations that do not exceed $10.0 million;



(20)

Liens on accounts receivable and related assets of the type specified in the definition of "Receivables Financing" incurred in connection with a Qualified Receivables Financing;



(21)

licenses of intellectual property in the ordinary course of business;



(22)

Liens on Capital Stock of an Unrestricted Subsidiary that secure Indebtedness or other obligations of such Unrestricted Subsidiary;



(23)

[Reserved];



(24)

Liens to secure a defeasance trust;



(25)

Liens on equipment of the Company or any Restricted Subsidiary granted in the ordinary course of business to clients of which such equipment is located;



(26)

Liens securing insurance premium financing arrangements, provided that such Lien is limited to the applicable insurance contracts;



(27)

[Reserved];



(28)

Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the property that is the subject of such Production Payments and Reserve Sales;



(29)

Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;



(30)

Liens on pipelines or pipeline facilities that arise by operation of law;



(31)

Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to commodity trading accounts or other brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

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(32)

Liens securing Hedging Obligations; and



(33)

any (a) interest or title of a lessor or sublessor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such leases; (b) restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics' liens, tax liens, and easements); or (c) subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b) in this subclause (33).

        "Permitted Payments to Parent" means, without duplication as to amounts:

(1)

payments to any parent companies of the Company in amounts equal to the amounts required for any direct payment of the Company to pay fees and expenses (including franchise or similar taxes) required to maintain its corporate existence, customary salary, bonus and other benefits payable to officers and employees of any direct parent of the Company and general corporate overhead expenses of any direct parent of the Company to the extent such fees and expenses are attributable to the ownership or operation of the Company and its Subsidiaries in an amount not to exceed $3.5 million; and



(2)

for so long as the Company is a member of a group filing a consolidated or combined tax return with such parent companies, payments to such parent companies in respect of an allocable portion of the tax liabilities of such group that is attributable to the Company and its Subsidiaries ("Tax Payments"). The Tax Payments shall not exceed the lesser of (i) the amount of the relevant tax (including any penalties and interest) that the Company would owe if the Company were filing a separate tax return (or a separate consolidated or combined return with its Subsidiaries that are members of the consolidated or combined group), taking into account any carryovers and carrybacks of tax attributes (such as net operating losses) of the Company and such Subsidiaries from other taxable years and (ii) the net amount of the relevant tax that such parent companies actually owe to the appropriate taxing authority. Any Tax Payments received from the Company shall be paid over to the appropriate taxing authority within 30 days of such parent companies' receipt of such Tax Payments or refunded to the Company.

        "Permitted Refinancing Indebtedness" means any Indebtedness of the Company or any of the Company's Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge other Indebtedness of the Company or any of the Company's Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1)

the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged (plus any premium required to be paid on the Indebtedness being so renewed, refunded, replaced, defeased or discharged, plus the amount of all fees and expenses incurred in connection therewith);



(2)

such Permitted Refinancing Indebtedness has a final maturity date equal to or later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the remaining Weighted Average Life to Maturity of, the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; provided that this clause (2) shall not apply to debt under Credit Facilities;



(3)

if the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the notes, such Permitted Refinancing Indebtedness is subordinated in right of payment to, the notes on terms at least as favorable to the holders of

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notes as those contained in the documentation governing the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; and

(4)

such Refinancing Indebtedness shall not include Indebtedness of the Company or a Restricted Subsidiary that refinance Indebtedness of an Unrestricted Subsidiary.

        "Person" means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

        "Priority Lien" means a Lien granted, or purported to be granted, by any Issuer or any Guarantor in favor of the Priority Lien Collateral Agent, at any time, upon any Property of any Issuer or any Guarantor to secure Priority Lien Obligations.

        "Priority Lien Cap" means, as of any date, (a) the principal amount of Indebtedness (including any interest paid-in-kind) that may be incurred under clause (1) of the definition of "Permitted Debt" as of such date (it being understood that any Indebtedness incurred under clause (ii) of clause (1) of the definition of "Permitted Debt" shall be permitted hereunder so long as such Indebtedness was permitted to be incurred at the time of incurrence), plus (b) the amount of all Hedging Obligations, to the extent such Hedging Obligations are secured by the Priority Liens, plus (c) the amount of all Banking Services Obligations to the extent such Banking Services Obligations are secured by the Priority Liens, plus (d) the amount of accrued and unpaid interest (excluding any interest paid-in-kind) and outstanding fees, to the extent such Obligations are secured by the Priority Liens. For purposes of this definition, all letters of credit will be valued at the face amount thereof, whether or not drawn.

        "Priority Lien Collateral Agent" means the Credit Facility Agent in its capacity as the collateral agent (or other Person designated in such capacity by the Credit Facility Agent), or if the Credit Agreement or any Refinancing Credit Agreement ceases to exist, the collateral agent or other representative of lenders or holders of Priority Lien Obligations designated pursuant to the terms of the Priority Lien Documents and the Intercreditor Agreement).

        "Priority Lien Debt" means (a) Indebtedness of any Issuer and the Guarantors under the Credit Agreement (including letters of credit (with outstanding letters of credit being deemed to have a principal amount equal to the stated amount thereof) and reimbursement obligations with respect thereto) or any Refinancing Credit Agreement that is, in each case, subject to the Intercreditor Agreement and permitted to be incurred under clause 1 of the definition of "Permitted Debt" and secured under each applicable Secured Debt Document and (b) additional Indebtedness of any Issuer and the Guarantors under any other Credit Facility that is secured with the Credit Agreement by a Priority Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document; provided, in the case of any Indebtedness referred to in this clause (b), that:

(1)

on or before the date on which Indebtedness is incurred under such Credit Facility, such Indebtedness is designated by the Company, in an officers' certificate delivered to the Priority Lien Collateral Agent, the Note Collateral Agent and any Junior Lien Collateral Agent, as "Priority Lien Debt" for the purposes of the Secured Debt Documents; provided that if such Indebtedness is designated as "Priority Lien Debt," it cannot also be designated as Parity Lien Debt or Junior Lien Debt (or any combination of the three);



(2)

the Priority Lien Collateral Agent, the Note Collateral Agent and the Junior Lien Collateral Agent shall receive (x) an officer's certificate from the Company stating that the incurrence thereof is permitted by each applicable Secured Debt Document to be incurred and certain other requirements of the Intercreditor Agreement are satisfied and (y) a joinder required by the Intercreditor Agreement from the holders or lenders of any such Indebtedness (or an authorized agent, trustee or other representative on their behalf);

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(3)

the aggregate outstanding principal amount of the Priority Lien Obligations, after giving effect to such Credit Facility, shall not exceed the Priority Lien Cap;



(4)

all other requirements set forth in the Intercreditor Agreement as to the confirmation, grant or perfection of the Priority Lien Collateral Agent's Liens to secure such Indebtedness or Obligations in respect thereof are satisfied; and



(5)

all such Indebtedness is pari passu in right of payment, it being understood that there may be different tranches of Priority Lien Debt with different maturities and amortization profiles, but the principal amount of Indebtedness under all such tranches must in all other respects be pari passu in right of payment. Any such Indebtedness that is not consistent with the foregoing requirement for pari passu treatment in right of payment with the other Indebtedness under the Priority Lien Documents shall not constitute Priority Lien Debt.

        "Priority Lien Documents" means any Credit Facility pursuant to which any Priority Lien Debt is incurred, the documents pursuant to which Priority Lien Obligations are granted and the Priority Lien Security Documents.

        "Priority Lien Security Documents" means all security agreements, pledge agreements, collateral assignments, mortgages, deeds of trust, collateral agency agreements, control agreements or other grants or transfers for security executed and delivered by any Issuer or any Guarantor creating (or purporting to create) a Lien upon Collateral in favor of the Priority Lien Collateral Agent, in each case, as amended, modified, renewed, restated or replaced, in whole or in part, from time to time, in accordance with its terms.

        "Priority Lien Obligations" means the Priority Lien Debt and all other Obligations in respect of Priority Lien Debt, Hedging Obligations and Banking Services Obligations.

        "Priority Lien Representative" means (a) the Credit Facility Agent or (b) in the case of any other Series of Priority Lien Debt, the trustee, agent or representative of the holders of such Series of Priority Lien Debt who maintains the transfer register for such Series of Priority Lien Debt and is appointed as a representative of the Priority Lien Debt (for purposes related to the administration of the Priority Lien Security Documents) pursuant to the credit agreement or any other agreement governing such Series of Priority Lien Debt.

        "Production Payments and Reserve Sales" means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

        "Purchase Money Note" means a promissory note of a Receivables Subsidiary evidencing a line of credit, which may be irrevocable, from the Company or any Subsidiary of the Company to a Receivables Subsidiary in connection with a Qualified Receivables Financing, which note is intended to finance that portion of the purchase price that is not paid by cash or a contribution of equity.

        "Property" means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights.

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        "Proved Reserves" means "Proved Reserves" as defined in the Definitions for Oil and Gas Reserves (the "Reserve Definitions") promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

        "Qualified Receivables Financing" means any Receivables Financing of a Receivables Subsidiary that meets the following conditions:

(1)

the Board of Directors of the Company will have determined in good faith that such Qualified Receivables Financing (including financing terms, covenants, termination events and other provisions) is in the aggregate economically fair and reasonable to the Company and the Receivables Subsidiary,



(2)

all sales of accounts receivable and related assets to the Receivables Subsidiary are made at Fair Market Value (as determined in good faith by the Company), and



(3)

the financing terms, covenants, termination events and other provisions thereof will be market terms (as determined in good faith by the Company) and may include Standard Securitization Undertakings.

        The grant of a security interest in any accounts receivable of the Company or any of its Restricted Subsidiaries (other than a Receivables Subsidiary) to secure a Credit Facility will not be deemed a Qualified Receivables Financing. For purposes of the indenture, a receivables facility whether now in existence or arising in the future (and any replacement thereof with substantially similar terms in the aggregate) will be deemed to be a Qualified Receivables Financing that is not recourse to the Company (except for Standard Securitization Undertakings).

        "Rating Agency" means each of S&P and Moody's, or if S&P or Moody's or both shall not make a rating on the notes publicly available, a nationally recognized statistical rating organization or organizations, within the meaning of Rule 15c3-1(c)(2)(vi)(F) under the Exchange Act, selected by the Company as a replacement agency or agencies for S&P or Moody's, or both, as the case may be.

        "Receivables Financing" means any transaction or series of transactions that may be entered into by the Company or any of its Subsidiaries pursuant to which the Company or any of its Subsidiaries may sell, convey or otherwise transfer to (a) a Receivables Subsidiary (in the case of a transfer by the Company or any of its Subsidiaries), and (b) any other Person (in the case of a transfer by a Receivables Subsidiary), or may grant a security interest in, any accounts receivable (whether now existing or arising in the future) of the Company or any of its Subsidiaries, and any assets related thereto, including, without limitation, all collateral securing such accounts receivable, all contracts and all guarantees or other obligations in respect of such accounts receivable, proceeds of such accounts receivable and other assets which are customarily transferred or in respect of which security interests are customarily granted in connection with asset securitization transactions involving accounts receivable and any Hedging Obligations entered into by the Company or any such Subsidiary in connection with such accounts receivable.

        "Receivables Repurchase Obligation" means any obligation of a seller of receivables in a Qualified Receivables Financing to repurchase receivables arising as a result of a breach of a representation, warranty or covenant or otherwise, including as a result of a receivable or portion thereof becoming subject to any asserted defense, dispute, off-set or counterclaim of any kind as a result of any action taken by, any failure to take action by or any other event relating to the seller.

        "Receivables Subsidiary" means a Wholly Owned Restricted Subsidiary of the Company (or another Person formed for the purposes of engaging in a Qualified Receivables Financing with the Company in which the Company or any Subsidiary of the Company makes an Investment and to which the Company or any Subsidiary of the Company transfers accounts receivable and related assets) which engages in no activities other than in connection with the financing of accounts receivable of the

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Company and its Subsidiaries, all proceeds thereof and all rights (contractual or other), collateral and other assets relating thereto, and any business or activities incidental or related to such business, and which is designated by the Board of Directors of the Company (as provided below) as a Receivables Subsidiary and:

(1)

no portion of the Indebtedness or any other obligations (contingent or otherwise) of which (i) is guaranteed by the Company or any other Subsidiary of the Company (excluding guarantees of obligations (other than the principal of, and interest on, Indebtedness) pursuant to Standard Securitization Undertakings), (ii) is recourse to or obligates the Company or any other Subsidiary of the Company in any way other than pursuant to Standard Securitization Undertakings, or (iii) subjects any property or asset of the Company or any other Subsidiary of the Company, directly or indirectly, contingently or otherwise, to the satisfaction thereof, other than pursuant to Standard Securitization Undertakings,



(2)

with which neither the Company nor any other Subsidiary of the Company has any material contract, agreement, arrangement or understanding other than on terms which the Company reasonably believes to be no less favorable to the Company or such Subsidiary than those that might be obtained at the time from Persons that are not Affiliates of the Company, and



(3)

to which neither the Company nor any other Subsidiary of the Company has any obligation to maintain or preserve such entity's financial condition or cause such entity to achieve certain levels of operating results. Any such designation by the Board of Directors of the Company shall be evidenced to the trustee by filing with the trustee a certified copy of the resolution of the Board of Directors of the Company giving effect to such designation and an Officer's Certificate certifying that such designation complied with the foregoing conditions.

        "Refinancing Credit Facility" has the meaning set forth for such term in the definition of "Credit Agreement."

        "Registration Rights Agreement" means that certain registration rights agreement, dated as the Issue Date, among the Issuers and the initial purchaser named therein, as such agreement may be amended, modified or supplemented from time to time.

        "Related Party" means:

(1)

any director, partner, manager, controlling stockholder, majority owned Subsidiary, or immediate family member (in the case of an individual) of any Permitted Holder; or



(2)

any trust, corporation, partnership, limited liability company or other entity, the beneficiaries, stockholders, partners, members, owners or Persons beneficially holding a majority (and controlling) interest of which consist of any one or more Permitted Holders and/or such other Persons referred to in the immediately preceding clause (1).

        "Reporting Failure" means the failure of the Company or a Guarantor to file with the SEC, make available, post or otherwise deliver to the trustee and each holder of notes, within the time periods specified in "—Certain Covenants—Reports" (after giving effect to any grace period specified under Rule 12b-25 under the Exchange Act), the periodic reports, information, documents or other reports which the Company or a Guarantor may be required to file with the SEC, make available, post or otherwise deliver pursuant to such provision.

        "Reserve Definitions" has the meaning set forth for such term in the definition of "Proved Reserves" herein.

        "Reserve Report" means a report, in a form substantially consistent with (as determined in good faith by the Company) with the form of "Reserve Report" required under the Credit Agreement, covering proved Oil and Gas reserves attributable to the Oil and Gas Properties and setting forth

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(i) the total quantity of proved developed and proved undeveloped reserves (separately classified as producing, shut-in, behind pipe, and undeveloped), (ii) the estimated future net revenues and future net income and cumulative estimated future net revenues and future net income utilizing a 9% discount rate (iii) the discounted present value of future net income utilizing a 9% discount rate, and (iv) such other information and data with respect to the Oil and Gas Properties as required under the Credit Agreement or any Refinancing Credit Agreement.

        "Restricted Investment" means an Investment other than a Permitted Investment.

        "Restricted Subsidiary" of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary. Unless specified otherwise, references herein to a Restricted Subsidiary refer to a Restricted Subsidiary of the Company.

        "S&P" means Standard & Poor's Ratings Services and any successor to its rating agency business.

        "SEC" means the Securities and Exchange Commission.

        "Secured Debt" means Priority Lien Debt, Parity Lien Debt and Junior Lien Debt.

        "Secured Debt Documents" means the Priority Lien Documents, the Note Documents and the Junior Lien Documents.

        "Securities Act" means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

        "Series of Priority Lien Debt" means, severally, the Indebtedness outstanding under the Credit Agreement, any Refinancing Credit Agreement and any other Credit Facility that constitutes Priority Lien Debt.

        "Significant Subsidiary" means any Subsidiary that would be a "significant subsidiary" as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the Issue Date.

        "Specified Indebtedness" means (i) the Existing Notes, (ii) the notes, (iii) the Junior Lien Notes and (iv) any other Indebtedness (other than Priority Lien Obligations) of the Company and its Restricted Subsidiaries incurred to refinance any of such Indebtedness listed in clauses (i) through (iii) above.

        "Standard Securitization Undertakings" means representations, warranties, covenants, indemnities and guarantees of performance entered into by the Company or any Subsidiary of the Company which the Company has determined in good faith to be customary in a Receivables Financing including, without limitation, those relating to the servicing of the assets of a Receivables Subsidiary, it being understood that any Receivables Repurchase Obligation shall be deemed to be a Standard Securitization Undertaking.

        "Start Date" means July 1, 2015.

        "Stated Maturity" means, with respect to any installment of principal on any series of Indebtedness, the date on which the final payment of principal was scheduled to be paid in the documentation governing such Indebtedness as of the Issue Date, and does not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

        "Subsidiary" means, with respect to any specified Person:

(1)

any corporation, association or other business entity (other than a partnership) of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement or stockholders' agreement that effectively transfers voting power) to vote in the election of directors,

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managers or trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2)

any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).

        "Treasury Management Agreement" means any agreement or other arrangement governing the provision of treasury or cash management services, including deposit accounts, overdraft, credit or debit card, funds transfer (including electronic funds transfer), automated clearinghouse, zero balance accounts, returned check concentration, controlled disbursement, lockbox, interstate depositary network services, account reconciliation and reporting and trade finance services and other cash management services.

        "Trustee" means the respective party named as such in the Indenture until a successor replaces it and, thereafter, means the successor.

        "Treasury Rate" means, as of any Redemption Date, the yield to maturity as of such Redemption Date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two Business Days prior to the Redemption Date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the Redemption Date to June 1, 2017; provided, however, that if the period from the Redemption Date to June 1, 2017, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

        "Unrestricted Subsidiary" means:

(1)

any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and



(2)

any Subsidiary of an Unrestricted Subsidiary.

        The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary of the Company) to be an Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns any Equity Interests or Indebtedness of, or owns or holds any Lien on any property of, the Company or any other Restricted Subsidiary that is not a Subsidiary of the Subsidiary to be so designated; provided, however, that the Subsidiary to be so designated and its Subsidiaries (i) do not at the time of designation have and do not thereafter incur Indebtedness that is not Non-Recourse Debt (other than guarantees of performance of the Unrestricted Subsidiary in the ordinary course of business, excluding guarantees of Indebtedness for borrowed money), (ii) is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company; and (iii) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) other than on a non-recourse basis, to maintain or preserve such Person's financial condition or to cause such Person to achieve any specified levels of operating results, provided, further, however, that such designation would be permitted under the covenant entitled "—Certain Covenants—Restricted Payments."

        "Voting Stock" of any specified Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

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        "Weighted Average Life to Maturity" means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1)

the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by



(2)

the then outstanding principal amount of such Indebtedness.

        "Wholly Owned Restricted Subsidiary" of any specified Person means a Subsidiary of such Person all of the outstanding Capital Stock or other ownership interests of which (other than directors' qualifying shares) will at the time be owned by such Person or by one or more Wholly Owned Restricted Subsidiaries of such Person.

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BOOK ENTRY; DELIVERY AND FORM

        The new notes will be issued initially only in the form of one or more global notes (collectively "Global Notes"). Beneficial interests in the Global Notes may be held through the Euroclear System, or Euroclear, and Clearstream Banking, S.A., or Clearstream, (as indirect participants in DTC). Global Notes will be deposited upon issuance with the Trustee as custodian for DTC, and registered in the name of DTC's nominee, Cede & Co., in each case for credit to an account of a direct or indirect participant in DTC as described below. The Global Notes may be transferred only to another nominee of DTC or to a successor of DTC or its nominee, in whole and not in part. Except in the limited circumstances described below, beneficial interests in Global Notes may not be exchanged for notes in certificated form and owners of beneficial interests in Global Notes will not be entitled to receive physical delivery of notes in certificated form. See "—Exchange of Certificated Notes for Global Notes."

        In addition, transfers of beneficial interests in Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including Euroclear and Clearstream), which may change from time to time.

Depository Procedures

        The following description of the operations and procedures of DTC, Euroclear and Clearstream is provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

        DTC has advised us that DTC is a limited-purpose trust company organized under the laws of the State of New York, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the Uniform Commercial Code and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participating organizations (collectively, the "Participants") and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

        DTC has also advised us that, pursuant to procedures established by it:

(1)

upon deposit of the Global Notes for the notes, DTC will credit the accounts of Participants designated by the exchange agent with portions of the principal amount of the Global Notes for the notes; and



(2)

ownership of these interests in Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in Global Notes).

        Investors in Global Notes who are Participants in DTC's system may hold their interests therein directly through DTC. Investors in Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) that are Participants in

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DTC. All interests in a Global Note may be subject to the procedures and requirements of DTC. Euroclear and Clearstream may hold interests in Global Notes on behalf of their participants through customers' securities accounts in their respective names on the books of their depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream which in turn hold such interests in customers' securities accounts in the depositaries' names on the books of DTC. Interests in a Global Note held through Euroclear or Clearstream may be subject to the procedures and requirements of those systems (as well as to the procedures and requirements of DTC). The laws of some states require that certain persons take physical delivery in definitive form of securities that they own and the ability to transfer beneficial interests in a Global Note to Persons that are subject to those requirements will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a person having beneficial interests in a Global Note to pledge those interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of those interests, may be affected by the lack of a physical certificate evidencing those interests.

        Except as described below, owners of interests in Global Notes will not have notes registered in their names, will not receive physical delivery of definitive notes in registered certificated form, or Certificated Notes, and will not be considered the registered owners or "Holders" thereof under the Indenture for any purpose.

        Payments in respect of the principal of, interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered Holder under the Indenture. Under the terms of the Indenture, we and the Trustee will treat the Persons in whose names notes, including Global Notes, are registered as the owners of such notes for the purpose of receiving payments and for all other purposes. Consequently, neither we, the Trustee nor our agent or an agent of the Trustee has or will have any responsibility or liability for:

(1)

any aspect of DTC's records or any Participant's or Indirect Participant's records relating to or payments made on account of beneficial ownership interests in Global Notes or for maintaining, supervising or reviewing any of DTC's records or any Participant's or Indirect Participant's records relating to the beneficial ownership interests in Global Notes; or



(2)

any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

        DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on that payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the notes as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or us. Neither we nor the Trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of any notes, and we and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

        Transfers between Participants in DTC will be effected in accordance with DTC's procedures, and will be settled in same-day funds and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

        Cross-market transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC's rules on behalf of Euroclear or Clearstream, as the case may be, by its depositary; however, such

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cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note from DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

        DTC has advised us that it will take any action permitted to be taken by a Holder of a given series of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the applicable series of Global Notes and only in respect of the portion of the aggregate principal amount of the applicable series of notes as to which that Participant or those Participants has or have given the relevant direction. However, if there is an Event of Default under such series of notes, DTC reserves the right to exchange the applicable Global Notes for legended notes in certificated form, and to distribute those notes to its Participants.

        Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures in order to facilitate transfers of interests in Global Notes among Participants, they are under no obligation to perform those procedures, and may discontinue or change those procedures at any time. Neither we nor the Trustee nor any of their respective agents will have any responsibility for the performance by DTC, Euroclear, Clearstream or their respective Participants or Indirect Participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

        A Global Note is exchangeable for a Certificated Note if:

•

DTC (1) notifies us that it is unwilling or unable to continue as depositary for the applicable Global Notes or (2) has ceased to be a clearing agency registered under the Exchange Act and, in either event, a successor depositary is not appointed;



•

we, at our option and subject to the procedures of DTC, notify the Trustee in writing that we elect to cause the issuance of Certificated Notes; or



•

there has occurred and is continuing a Default or an Event of Default with respect to the Notes.

        Beneficial interests in a Global Note may also be exchanged for Certificated Notes in the other limited circumstances permitted by the indenture, including if an affiliate of ours acquires such interests. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in a Global Note will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Exchange of Certificated Notes for Global Notes

        Certificated Notes may not be exchanged for beneficial interests in any Global Note, except in the limited circumstances provided in the indenture.

Same-day Settlement and Payment

        We will make payments in respect of notes represented by Global Notes, including payments of principal, premium, if any, and interest by wire transfer of immediately available funds to the accounts specified by the Global Note Holders. We will make all payments of principal of and premium, if any, and interest on Certificated Notes by wire transfer of immediately available funds to the accounts specified by the Holders of the Certificated Notes or, if no account is specified, by mailing a check to

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each Holder's registered address. See "Description of New Notes—Principal, Maturity and Interest." Notes represented by Global Notes are eligible to trade in DTC's Same-Day Funds Settlement System, and any permitted secondary market trading activity in notes represented by Global Notes will, therefore, be required by DTC to be settled in immediately available funds. Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC's settlement date.

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MATERIAL U.S. FEDERAL INCOME TAX AND ESTATE TAX CONSEQUENCES

        The following is a summary of material U.S. federal income tax consequences, and in the case of a non-U.S. holder (as defined below), material estate tax consequences, of the exchange of the old notes for the new notes pursuant to the exchange offer and the ownership and disposition of the new notes issued pursuant to the exchange offer, but does not purport to be a complete analysis of all the potential tax consequences. This summary is based on the U.S. Internal Revenue Code of 1986, as amended (the "Code"), the U.S. Treasury Regulations promulgated thereunder ("Treasury Regulations"), judicial authority, published administrative positions of the U.S. Internal Revenue Service ("IRS"), all as in effect on the date of this prospectus and all of which are subject to change, possibly with retroactive effect, or are subject to different interpretations. We have not sought, nor do we intend to seek, a ruling from the IRS or an opinion of counsel with respect to the statements made and the conclusions reached in the following summary and there can be no assurance that the IRS will agree with our statements and conclusions or that a court would not sustain any challenge by the IRS in the event of litigation.

        This summary deals only with beneficial owners of the notes that acquired the old notes upon their original issue from the initial purchaser for cash at their "issue price" (generally, the first price at which a substantial amount of the notes is sold for money to investors (excluding sales to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers)) and that hold the notes as "capital assets" within the meaning of Code Section 1221 (generally, property held for investment). This discussion does not purport to deal with all aspects of U.S. federal income and estate taxation that might be relevant to particular beneficial owners in light of their personal investment circumstances or status, nor does it address tax consequences applicable to beneficial owners that may be subject to special rules, such as banks and financial institutions, individual retirement and other tax-deferred accounts, tax-exempt entities, governments or government instrumentalities, S corporations, partnerships or other pass-through entities for U.S. federal income tax purposes or investors in such entities, insurance companies, regulated investment companies, real estate investment trusts, broker-dealers, dealers or traders in securities or currencies, certain former citizens or residents of the U.S. subject to Code Section 877, controlled foreign corporations, non-U.S. trusts or estates with U.S. beneficiaries, passive foreign investment companies, corporations that accumulate earnings to avoid U.S. federal income tax and taxpayers subject to the alternative minimum tax or the Medicare tax on certain investment income. This summary also does not discuss notes held as part of a hedge, straddle, synthetic security, constructive sale, integrated or conversion transaction, situations in which the "functional currency" of a U.S. Holder (as defined below) is not the U.S. dollar or situations where a U.S. holds a note through a bank, financial institution or other entity or a branch thereof, that is located, organized or resident outside the U.S. Moreover, the effect of any U.S. federal non-income taxes (such as gift taxes) and any state, local or non-U.S. tax laws or tax treaties are not discussed.

        In the case of a beneficial owner of notes that is treated as a partnership for U.S. federal income tax purposes, the tax treatment of the notes to a partner in the partnership generally will depend upon the tax status of the partner and the activities of the partner and partnership. If you are a partner of a partnership participating in the exchange offer or holding the new notes, then you should consult your own tax advisor about the U.S. federal income and estate tax consequences applicable to you or the partnership's participation in the exchange offer or holding and disposing of the new notes.

        This summary is for informational purposes only and is not a substitute for careful tax planning and advice. Investors considering participation in the exchange offer should consult their own tax advisors with respect to the application of the U.S. federal income tax laws to their particular situations, as well as any tax consequences arising under any other federal tax laws or the laws of any state, local or non-U.S. taxing jurisdiction or under any applicable tax treaty, and the possible effects of changes in U.S. federal tax laws, or in any applicable tax treaty.

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Effect of Certain Contingencies

        In certain circumstances (e.g., as described above under the heading "Description of New Notes—Repurchase at the Option of Holders—Change of Control," and "Description of New Notes—Optional Redemption"), we may be obligated to redeem the new notes prior to their maturity date or to pay amounts on the notes that are in excess of stated interest or principal on the new notes. These potential payments may also implicate the provisions of the Treasury Regulations relating to "contingent payment debt instruments." Although the issue is not free from doubt, we believe and intend to take the position that the new notes should not be treated as contingent payment debt instruments for U.S. federal income tax purposes. This position is based in part on assumptions regarding the likelihood, as of the date of issuance of the notes, that such additional amounts will have to be paid.

        Our position that the new notes should not be treated as contingent payment debt instruments is binding on a holder, unless such holder timely and explicitly discloses to the IRS on its tax return for the year during which it acquires the notes that it is taking a different position. However, our position is not binding on the IRS. If the IRS takes a contrary position (i.e., that the new notes are treated as contingent payment debt instruments), regardless of a holder's method of tax accounting, a holder subject to U.S. federal income taxation might be required to accrue ordinary interest income on the new notes at a higher rate than the stated interest rate and to treat as ordinary income (rather than capital gain) any gain realized on the taxable sale, exchange, redemption, retirement or other taxable disposition of the new note. The remainder of this discussion assumes that the new notes will not be treated as contingent payment debt instruments for U.S. federal income tax purposes. Investors should consult their own tax advisors regarding the possible application of the contingent payment debt instrument rules to the new notes.

U.S. Holders

        The following is a summary of material U.S. federal income tax consequences if you are a U.S. Holder. For purposes of this summary, the term "U.S. Holder" means a beneficial owner of a note that is for U.S. federal income tax purposes:

•

an individual who is a citizen or a resident of the U.S.;



•

a corporation, or any other entity taxable as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the U.S., any state thereof or the District of Columbia;



•

an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or



•

a trust if (1) a court within the U.S. is able to exercise primary jurisdiction over its administration and one or more "United States persons" (within the meaning of the Code) have the authority to control all of its substantial decisions, or (2) the truest has a valid election in effect under applicable Treasury Regulations to be treated as a domestic trust for U.S. federal income tax purposes.

Participation in the Exchange Offer

        The exchange of old notes for new notes will not constitute a taxable event for U.S. federal income tax purposes. Consequently, U.S. Holders will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange offer. A U.S. Holder's tax basis in the new note received in the exchange offer will be the same as its tax basis in the corresponding old note immediately before the exchange, and a U.S. Holder's holding period in the new note will include its holding period in the old note.

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Payments of Stated Interest

        Stated interest on a new note generally will be included in the gross income of a U.S. Holder as ordinary income at the time such interest is accrued or received, in accordance with such holder's regular method of tax accounting for U.S. federal income tax purposes.

Sale, Exchange, Redemption, Retirement or Other Taxable Disposition of the New Notes

        Upon the sale, exchange, redemption, retirement or other taxable disposition of a new note, a U.S. Holder generally will recognize gain or loss equal to the difference, if any, between (i) the amount realized on the disposition, except any portion of such amount that is attributable to accrued but unpaid interest, which portion will be taxed as described above under "U.S. Holders—Payments of Stated Interest" to the extent not previously taxed, and (ii) the holder's adjusted tax basis in the new note. The amount realized generally will equal the sum of the amount of any cash and the fair market value of any other property received in exchange for the note. A U.S. Holder's adjusted tax basis in a new note generally will equal the amount the U.S. Holder paid for the old note that was exchanged for such new note. Any gain or loss on a disposition of a new note generally will be capital gain or loss, and will be long-term capital gain or loss if the U.S. Holder held the note for more than one year at the time of the disposition. In general, long-term capital gains of a non-corporate U.S. Holder are taxed at lower rates than those applicable to ordinary income. The deductibility of capital losses is subject to limitations. Each U.S. Holder should consult its own tax advisors as to the deductibility of capital losses in its particular circumstances.

Information Reporting and Backup Withholding

        In general, we must report certain information to the IRS and to certain U.S. Holders with respect certain payments of principal, premium (if any) and interest on a note and certain payments of the proceeds of a sale or other disposition (including a redemption or retirement) of a new note, except in the case of an exempt recipient (such as a corporation). The applicable withholding agent (which may be us or an intermediate payor) will be required to impose backup withholding, currently at a rate of 28 percent, with respect to the foregoing amounts if (i) the payee fails to furnish a taxpayer identification number ("TIN") to the payor or to establish an exemption from backup withholding; (ii) the IRS notifies the payor that the TIN furnished by the payee is incorrect, (iii) there has been a notified payee underreporting described in Code Section 3406(c) or (iv) the payee has not certified under penalties of perjury that it has furnished a correct TIN, that it is a U.S. person and that the IRS has not notified the payee that it is subject to backup withholding under the Code.

        U.S. backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules from a payment to a U.S. Holder will be allowed as a credit against the holder's U.S. federal income tax liability, if any, and may entitle the holder to a refund, provided that the required information is timely furnished to the IRS.

Non-U.S. Holders

        The following is a summary of material U.S. federal income tax consequences if you are a non-U.S. Holder. For purposes of this summary, the term "non-U.S. Holder" means a beneficial owner of a note that is, for U.S. federal income tax purposes, a nonresident alien individual, a foreign corporation, or a foreign estate or trust.

Participation in the Exchange Offer

        The exchange of old notes for new notes will not constitute a taxable event for U.S. federal income tax purposes. Consequently, Non-U.S. Holders will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange offer. A Non-U.S. Holder's tax basis in the new

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note received in the exchange offer will be the same as its tax basis in the corresponding old note immediately before the exchange, and a Non-U.S. Holder's holding period in the new note will include its holding period in the old note.

Payments of Interest

        Subject to the discussions of the backup withholding and FATCA below, interest paid on a new note by us or any paying agent to a non-U.S. Holder will be exempt from U.S. federal income and withholding tax under the "portfolio interest exemption" provided that such interest is not effectively connected with a U.S. trade or business conducted by the non-U.S. Holder and (i) the non-U.S. Holder does not, actually or constructively, own 10% or more of the total combined voting power of all classes of our stock entitled to vote, (ii) the non-U.S. Holder is not a controlled foreign corporation related to us, actually or constructively, through stock ownership (iii) the non-U.S. Holder is not a bank that acquired the notes in consideration for an extension of credit made pursuant to a loan agreement entered into in the ordinary course of its trade or business, and (iv) either (a) the non-U.S. Holder provides to us or our paying agent a properly completed applicable IRS Form W-8BEN or W-8BEN-E and any applicable attachments, signed under penalties of perjury, that includes its name and address and that certifies it is not a U.S. person, or in the case of an individual, that the person is neither a citizen or a resident (for U.S. federal income tax purposes) of the U.S., in compliance with applicable law and regulations, or (b) a securities clearing organization, bank or other financial institution that holds customers' securities in the ordinary course of its trade or business on behalf of the non-U.S. Holder provides a statement to us or our agent under penalties of perjury in which it certifies that a properly completed applicable IRS Form W-8BEN or W-8BEN-E and any applicable attachments has been received by it from the non-U.S. Holder, or (c) the non-U.S. Holder holds its new notes through a "qualified intermediary" and the qualified intermediary furnishes a copy us or our agent of a properly executed IRS Form W-8IMY and any applicable attachments on behalf of itself (which may, in some circumstances, include a withholding statement and applicable underlying IRS forms sufficient to establish that the non-U.S. Holder is not a U.S. Holder). This certification requirement may be satisfied with other documentary evidence in the case of a new note held as an offshore obligation or through certain foreign intermediaries, if certain requirements are met.

        If a non-U.S. Holder cannot satisfy the requirements of the portfolio interest exemption described above, payments of interest made to such holder generally will be subject to U.S. federal withholding tax at the rate of 30%, unless the holder provides us or our agent with a properly executed IRS Form W-8BEN or W-8BEN-E and any applicable attachments establishing an exemption from, or reduction in, the withholding tax under the benefit of an applicable tax treaty.

Sale, Exchange, Redemption, Retirement or other Taxable Disposition of the New Notes

        Subject to the discussions of the FATCA legislation and backup withholding below, a non-U.S. Holder generally will not be subject to U.S. federal income or withholding tax on any gain realized on a sale, exchange, redemption, retirement or other taxable disposition of a new note (other than any amount representing accrued but unpaid interest on the new note, which may be subject to the rules discussed above under "Non-U.S. Holders—Payment of Interest") unless: (i) such gain is effectively connected with the conduct by such non-U.S. Holder of a trade or business within the U.S., in which case the gain will be treated as described below under "Non-U.S. Holders—U.S. Trade or Business;" or (ii) the non-U.S. Holder is an individual who was present in the U.S. for 183 days or more in the taxable year of the disposition and certain other conditions are met, in which case such non-U.S. Holder generally will be subject to U.S. federal income tax at a flat rate of 30 percent (unless a lower applicable treaty rate applies) on such holder's net U.S.-source gain.

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U.S. Trade or Business

        If interest paid on a new note or gain realized from a disposition of a new note is effectively connected with a non-U.S. Holder's conduct of a U.S. trade or business, and if required by an applicable income tax treaty applies and the non-U.S. Holder maintains a U.S. "permanent establishment" to which the interest or gain is attributable, the non-U.S. Holder generally will be subject to U.S. federal income tax on the interest and gain on a net basis in the same manner as if it were a U.S. Holder. If interest received with respect to the new notes is taxable on a net basis, the 30% withholding tax described above will not apply (assuming an appropriate certification is provided). In addition, a foreign corporation that is a holder of a new note also may be subject to a branch profits tax equal to 30% of its effectively connected earning and profits for the taxable year, subject to certain adjustments, unless it qualifies for a lower rate under an applicable income tax treaty. For this purpose, interest on a new note or gain recognized on the disposition of a new note will be included in earnings and profits if the interest or gain is effectively connected with the conduct by the foreign corporation of a trade or business in the U.S. Non-U.S. Holders should consult their tax advisors about any applicable income tax treaties, which may provide for rules different from those described above.

U.S. Federal Estate Tax

        For a non-U.S. Holder that is an individual and not a resident of the U.S. (as specially defined for U.S. federal estate tax purposes) at the time of his or her death, the new notes will not be included in such non-U.S. Holder's estate for U.S. federal estate tax purposes provided, at the time of death, interest on the new notes qualifies for the portfolio interest exemption under the rules described above in "Non-U.S. Holders—Payments of Interest" (without regard to the certification requirement).

Information Reporting and Backup Withholding

        The amount of interest on a new note paid to a non-U.S. Holder and the amount of tax, if any, withheld from any such payment generally must be reported annually to the non-U.S. Holder and to the IRS. The IRS may make this information available under the provisions of an applicable income tax treaty to the tax authorities in the country in which the non-U.S. Holder is resident.

        Provided that a non-U.S. Holder has complied with certain reporting procedures (usually satisfied by providing an applicable properly completed IRS Form W-8BEN or IRS Form W-8BEN-E) or otherwise establishes an exemption, the non-U.S. Holder generally will not be subject to backup withholding tax with respect to interest payments on, and the proceeds from a disposition of, a new note, unless we or our paying agent know or have reason to know that the holder is a U.S. person. Rules relating to information reporting requirements and backup withholding with respect to the payment of proceeds from the taxable disposition (including a redemption or retirement) of a new note are as follows:

•

If the proceeds are paid to or through the U.S. office of a broker, a non-U.S. Holder generally will be subject to backup withholding and information reporting unless the non-U.S. Holder certifies under penalties of perjury that it is not a U.S. person (usually on an IRS Form W-8BEN or W-8BEN-E) or otherwise establishes an exemption.



•

If the proceeds are paid to or through a non-U.S. office of a broker that is not a U.S. person and does not have certain specified U.S. connections (a "U.S. Related Person"), a non-U.S. Holder generally will not be subject to backup withholding or information reporting.



•

If the proceeds are paid to or through a non-U.S. office of a broker that is a U.S. person or a U.S. Related Person, a non-U.S. Holder generally will be subject to information reporting (but generally not backup withholding) unless the non-U.S. Holder certifies under penalties of perjury

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that it is not a U.S. person (usually on an IRS Form W-8BEN or an IRS Form W-8BEN-E) or otherwise establishes an exemption.

        Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules from a payment to a non-U.S. Holder may be allowed as a credit against the non-U.S. Holder's U.S. federal income tax liability, if any, and may entitle the non-U.S. Holder to a refund, provided that the required information is timely furnished to the IRS. Non-U.S. Holders should consult their own tax advisors regarding the application of the backup withholding rules in their particular circumstances and the availability of, and procedure for, obtaining an exemption from backup withholding under current Treasury Regulations.

FATCA Legislation

        The Foreign Account Tax Compliance Act and the final Treasury Regulations and official IRS guidance associated with such provisions (such provisions, regulations and guidance commonly known as FATCA) generally imposes a U.S. federal withholding tax of 30 percent on interest paid on a debt obligation and on the gross proceeds of a sale or other disposition (including a redemption or retirement) of a debt obligation paid to (i) a foreign financial institution (as the beneficial owner or as an intermediary for the beneficial owner), unless such institution (a) enters into, and is in compliance with, a withholding and information reporting agreement with the U.S. government to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which would include certain equity and debt holders of such institution, as well as certain account holders that are foreign entities with U.S. owners) or (b) is a resident in a country that has entered into an intergovernmental agreement with the U.S. in relation to such withholding and information reporting and the financial institution complies with the related information reporting requirements of such country or, (ii) a foreign entity that is not a financial institution (as the beneficial owner or as an intermediary for the beneficial owner), unless such entity provides the withholding agent with a certification identifying the substantial U.S. owners of the entity, which generally includes any U.S. person who directly or indirectly owns more than 10 percent of the entity or certifies that it does not have any substantial U.S. owners.

        Withholding under FATCA generally will apply to payments of interest on a new note regardless of when they are made. However, under the applicable Treasury Regulations, withholding under FATCA generally will only apply to payments of gross proceeds from the sale or other disposition of a new note on or after January 1, 2017. An intergovernmental agreement between the U.S. and the applicable non-U.S. country, or future Treasury Regulations or other official IRS guidance, may modify these requirements. Investors should consult with their own tax advisors regarding the implications of this legislation on their participation in the exchange offer and their ownership and disposition of the new notes issued pursuant to the exchange offer.

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PLAN OF DISTRIBUTION

        Based on interpretations by the staff of the SEC in no-action letters issued to third parties, we believe that you may transfer new notes issued in the exchange offer in exchange for the old notes if:

•

you acquire the new notes in the ordinary course of your business; and



•

you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of such new notes.

        You may not participate in the exchange offer if you are:

•

an "affiliate" within the meaning of Rule 405 under the Securities Act; or



•

a broker-dealer that acquired old notes directly from us.

        Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver this prospectus in connection with any resale of such new notes. To date, the staff of the SEC has taken the position that broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as the exchange offer, other than a resale of an unsold allotment from the original sale of the old notes, with the prospectus contained in the registration statement relating to the exchange offer. On this basis, this prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of up to 180 days after the exchange date (as such period may be extended), we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until such date, all dealers effecting transactions in new notes may be required to deliver this prospectus.

        If you wish to exchange new notes for your old notes in the exchange offer, you will be required to make representations to us as described in "Exchange Offer—Procedures for Tendering—Your Representations to Us" in this prospectus. As indicated in the letter of transmittal, you will be deemed to have made these representations by tendering your old notes in the exchange offer. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge, in the same manner, that you will deliver this prospectus in connection with any resale by you of such new notes.

        We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:

•

in over-the-counter market;



•

in negotiated transactions;



•

through the writing of options on the new notes; or



•

a combination of such methods of resales;

at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices.

        Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes of any series that were received by it for its own account pursuant to the exchange offer and any broker or dealer that

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participates in a distribution of such new notes may be deemed to be an "underwriter" within the meaning of the Securities Act. Each letter of transmittal states that by acknowledging that it will deliver and by delivering this prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

        For a period of up to 180 days after the exchange date (as such period may be extended), we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the manner indicated in the letter of transmittal. We have agreed to pay all reasonable expenses incident to the exchange offer (including the expenses of one counsel for the holders of the old notes) other than commissions or concessions of any broker-dealers and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS

        The validity of the new notes and the related guarantees offered in the exchange offer will be passed upon for us by Kirkland & Ellis LLP, Houston, Texas.

EXPERTS

        The consolidated financial statements as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, included in this Prospectus and Registration Statement have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion on the consolidated financial statements and includes explanatory paragraphs regarding going concern uncertainty, retrospective adjustments to reflect a reverse stock split, and the correction of an error in operating and investing cash flows). Such consolidated financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

        Certain estimates of our net crude oil and natural gas reserves and related information for the Mississippian Lime and Anadarko Basin areas included in this prospectus have been derived from reports prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers, and all such information has been so included in reliance on the authority of that firm as experts regarding the matters contained in their report.

        Certain estimates of our net crude oil and natural gas reserves and related information for the Gulf Coast area included in this prospectus have been derived from reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, and all such information has been so included in reliance on the authority of that firm as experts regarding the matters contained in their report.

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AVAILABLE INFORMATION

        We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy documents filed by us with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC's website at http: //www.sec.gov.

        Our common stock is listed and traded on the NYSE under the symbol "MPO". Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the NYSE, 20 Broad Street, New York, New York 10005.

        We also make available free of charge on our website at http://www.midstatespetroleum.com all of the documents that we file with the SEC as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into, and does not constitute a part of, this prospectus.

        This prospectus is part of a registration statement that we have filed with the SEC relating to the securities to be offered. This prospectus does not contain all of the information we have included in the registration statement and the accompanying exhibits and schedules in accordance with the rules and regulations of the SEC, and we refer you to the omitted information. The statements this prospectus makes pertaining to the content of any contract, agreement or other document that is an exhibit to the registration statement necessarily are summaries of their material provisions and do not describe all exceptions and qualifications contained in those contracts, agreements or documents. You should read those contracts, agreements or documents for information that may be important to you. The registration statement, exhibits and schedules are available at the SEC's Public Reference Room or through its Internet website.

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INDEX TO FINANCIAL STATEMENTS

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands, Except Share Amounts)

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands, Except Per Share Amounts)

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)

(Unaudited)

(In Thousands)

 

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)

   

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

        Midstates Petroleum Company, Inc., through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas liquids ("NGLs") and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC ("Midstates Sub"), which was previously a wholly owned subsidiary of Midstates Petroleum Holdings LLC ("Holdings LLC"). The terms "Company," "we," "us," "our," and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary, unless the context indicates otherwise.

        The Company has oil and gas operations and properties in Oklahoma, Texas and Louisiana. The Company operated oil and natural gas properties as one reportable segment engaged in the exploration, development and production of oil, natural gas liquids and natural gas. The Company's management evaluates performance based on one reportable segment as all our operations are located in the United States and therefore we maintain one cost center.

2. Liquidity and Capital Resources

        As a result of substantial declines in oil, natural gas liquids and natural gas prices during the latter half of 2014 and continuing into 2015, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be impacted as current hedging contracts expire. During the three and six months ended June 30, 2015, the Company received cash payments on settled derivative contracts of $42.2 million and $94.8 million, respectively. The weighted average fixed price of the Company's derivatives for the second half of 2015 are lower than the weighted average fixed price for the first half of 2015, and the Company currently has no derivatives for any period subsequent to 2015. As such, the cash payments received during the first half of 2015 could significantly decrease in the second half of 2015, and such cash payments will not be received in 2016 and future periods due to the expiration of our hedging contracts.

        The interest payment obligations of the Company are substantial and the uncertainty associated with the Company's ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about the Company's ability to continue as a going concern. The Company received a going concern qualification from its independent registered public accounting firm for the year ended December 31, 2014, but obtained a waiver to the reserve based revolving credit facility ("the Credit Facility") waiving any default as a result of receiving such qualification. The accompanying financial statements do not include any adjustments that might result from the uncertainty associated with the Company's ability to meet obligations as they come due.

        As a result of the commodity price decline and the Company's substantial debt burden, the Company took steps to increase its liquidity and amended certain debt covenants. On April 21, 2015, the Company closed on the sale of certain of its oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana (the "Dequincy Divestiture"), for approximately $44.0 million, before customary post-closing adjustments. The net proceeds from the Dequincy Divestiture were retained for general corporate purposes. On May 21, 2015, the Company sold $625.0 million of 10.0% Second Lien Senior Secured Notes due 2020 (the "Second Lien Notes") and utilized the proceeds to repay the outstanding balance of the Credit Facility of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, the Company exchanged approximately $504.121 million of 12.0% Third Lien Senior Secured Notes due 2020 (the "Third Lien Notes") for approximately $279.8 million

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

2. Liquidity and Capital Resources (Continued)

of 10.75% Senior Unsecured Notes due 2020 (the "2020 Senior Notes") and $350.3 million of 9.25% Senior Unsecured Notes due 2021 (the "2021 Senior Notes" together with the 2020 Senior Notes, the "Unsecured Notes"), representing an exchange at 80.0% of the exchanged Unsecured Notes' par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes' par value. The Company also entered into a Seventh Amendment to the Credit Facility ("Seventh Amendment") which provided that upon completion of the Second Lien Notes and Third Lien Notes exchange, the borrowing base of the Credit Facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. For further information regarding the Second Lien Notes, Third Lien Notes and updates to the Company's debt covenants, see "—Note 10. Long-Term Debt." The Dequincy Divestiture, the issuance of the Second Lien Notes and the exchange of the Third Lien Notes increased the Company's cash balance, increased the amount of borrowings available under the Credit Facility and as a result, increased the liquidity of the Company.

3. Summary of Significant Accounting Policies

Basis of Presentation

        These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America ("GAAP") for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2014 included herein.

        All intercompany transactions have been eliminated in consolidation. In the opinion of the Company's management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Reverse Stock Split

        On August 3, 2015, the Company completed a 1-for-10 reverse stock split of its outstanding common stock. To effect the reverse stock split, the Company filed a Certificate of Amendment to the Company's Restated Certificate of Incorporation, which provides for the reverse stock split and for the corresponding reduction in the Company's authorized capital stock to 100 million shares of common stock, $0.01 par value per share, following the reverse stock split. The condensed consolidated financial statements and notes to the condensed consolidated financial statements included in this document give retrospective effect to the reverse stock split for all periods presented.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

Recently Issued Standards Not Yet Adopted

        In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"). ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period, considering the one year deferral approved by the FASB on July 9, 2015. The standard permits the use of either the retrospective or cumulative effect transition method. Early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

        In April 2015, the FASB issued Accounting Standards Update 2015-03, "Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835)". The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard should be applied retrospectively and is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of this guidance will have a material impact on its financial position, results of operations or cash flows.

Correction of Operating and Investing Cash Flows for the Six Months Ended June 30, 2014

        In the first quarter of 2015, the Company determined that it had incorrectly presented non-cash accrued capital expenditures in its Statements of Cash Flows since December 31, 2012. Management concluded the misstatement is immaterial to previously issued financial statements; however, the Company has corrected the cash flow presentation in the accompanying Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2014. There was no impact of the misstatement on the Condensed Consolidated Balance Sheet as of December 31, 2014, or on the Condensed Consolidated Statement of Operations for the three or six months ended June 30, 2014. The impact of the correction is shown in the following table (in thousands):

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

4. Fair Value Measurements of Financial Instruments

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments

        Commodity derivative contracts reflected in the condensed consolidated balance sheets are recorded at estimated fair value. At June 30, 2015 and December 31, 2014, all of the Company's commodity derivative contracts were with seven bank counterparties, and were classified as Level 2 in the fair value input hierarchy.

        Derivative instruments listed below are presented gross and consist of swaps that are carried at fair value. The Company records the net change in the fair value of these positions in "Gains (losses) on commodity derivative contracts—net" in the Company's unaudited condensed consolidated statements of operations. See "—Note 5. Risk Management and Derivative Instruments" for additional information on the Company's derivative instruments and balance sheet presentation.

 

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

5. Risk Management and Derivative Instruments

        The Company's production is exposed to fluctuations in crude oil, NGL and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil, NGL and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to reduce fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGL and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its crude oil, NGL and natural gas production.

        Inherent in the Company's portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company's counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company's counterparties failed to perform under existing commodity derivative contracts, the maximum loss at June 30, 2015 would have been approximately $35.9 million.

Commodity Derivative Contracts

        As of June 30, 2015, the Company had the following open commodity derivative contract positions:

Balance Sheet Presentation

        The following table summarizes the gross fair values of derivative instruments by the appropriate balance sheet classification; however, the derivative instruments are subject to netting arrangements and

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

5. Risk Management and Derivative Instruments (Continued)

qualify for net presentation in the Company's unaudited condensed consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively (in thousands):

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

5. Risk Management and Derivative Instruments (Continued)

Gains (losses) on Commodity Derivative Contracts

        The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in "Gains (losses) on commodity derivative contracts—net" within revenues in the unaudited condensed consolidated statements of operations.

        The following table presents net cash received (paid) for commodity derivative contracts and unrealized net gains (losses) recorded by the Company related to the change in fair value of the derivative instruments in "Gains (losses) on commodity derivative contracts—net" for the periods presented:

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

6. Property and Equipment

Oil and Gas Properties

        The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three and six months ended June 30, 2015 and 2014, the Company capitalized the following (in thousands):

        The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company's reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income.

        The Company performs a ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed this "ceiling." The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations ("ARO") accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying condensed consolidated statements of operations.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

6. Property and Equipment (Continued)

        At June 30, 2015, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $498.4 million. During the six months ended June 30, 2015 and 2014, the Company recorded impairments of oil and gas properties of $673.1 million and $86.5 million, respectively. Impairments at June 30, 2015 and March 31, 2015 were primarily due to continued low commodity prices, which resulted in a reduction of the discounted present value of the Company's proved oil and natural gas reserves.

        Depreciation, depletion and amortization is calculated using the Units of Production Method ("UOP"). The UOP calculation multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties for the three and six months ended June 30, 2015 and 2014, respectively:

        Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least quarterly to determine if impairment has occurred. Unevaluated property was $31.8 million and $44.5 million at June 30, 2015 and December 31, 2014, respectively.

Other Property and Equipment

        Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is calculated principally using the straight-line method over the estimated useful lives of the assets, which range from five to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

Sale of Dequincy Assets

        On April 21, 2015, the Company closed on the sale of its ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44.0 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42.4 million, which was net of customary closing adjustments, was reflected as a reduction of oil and natural gas properties,

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

6. Property and Equipment (Continued)

with no gain or loss recognized. The proceeds from the sale have been and will continue to be used for general corporate purposes.

7. Other Noncurrent Assets

        At June 30, 2015 and December 31, 2014 other noncurrent assets consisted of the following:

        During the three months ended June 30, 2015, approximately $4.6 million in deferred financing costs were impaired as a result of the Seventh Amendment to the Credit Facility. The Seventh Amendment is further discussed in "—Note 10. Long-Term Debt."

8. Accrued Liabilities

        At June 30, 2015 and December 31, 2014 accrued liabilities consisted of the following:

9. Asset Retirement Obligations

        Asset Retirement Obligations ("AROs") represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the ARO at inception is capitalized as part of the carrying amount of the related long-lived assets.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

9. Asset Retirement Obligations (Continued)

        The following table reflects the changes in the Company's AROs for the periods indicated:

10. Long-Term Debt

        The Company's long-term debt as of June 30, 2015 and December 31, 2014 is as follows (in thousands):

 

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

10. Long-Term Debt (Continued)

Debt Restructuring

        On May 21, 2015, the Company issued $625.0 million of Second Lien Notes and utilized the proceeds to repay the outstanding balance of the Credit Facility in an amount of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, the Company exchanged approximately $504.121 million of Third Lien Notes for approximately $279.8 million of 2020 Senior Notes and $350.3 million of 2021 Senior Notes, representing an exchange at 80.0% of the exchanged Unsecured Notes' par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes' par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and $70.7 million of the principal amount of 2021 Senior Notes were extinguished.

        Additionally, the Company and Midstates Sub entered into the Seventh Amendment to the Credit Facility which provided that upon completion of the offering of the Second Lien Notes and exchange of Third Lien Notes, the borrowing base of the Credit Facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found below. The exchanges of Third Lien Notes for the Unsecured Notes as well as the issuance of the Second Lien Notes were accounted for as a troubled debt restructuring. As the future cash flows of the modified debt instruments are greater than the carrying amount of the previous debt instruments, no gain was recognized. The amount of extinguished debt will be amortized and recognized as a reduction of interest expense over the remaining life of the Second Lien Notes and Third Lien Notes using the effective interest method. As a result, the Company's reported interest expense will be significantly less than the contractual interest payments throughout the term of Second Lien Notes and Third Lien Notes. All costs incurred, including restructuring costs as well as the direct issuance costs of the Second Lien Notes and Third Lien Notes, were expensed and are included within debt restructuring costs in our condensed consolidated statements of operations.

Reserve-based Credit Facility

        The Company maintains a $750.0 million Credit Facility with a borrowing base of $252.4 million supported by the Company's Mississippian Lime and Anadarko Basin oil and gas assets. At June 30, 2015, the Company had no amounts drawn on the Credit Facility and had outstanding letters of credit obligations totaling $1.5 million.

        The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of the Company's oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon the Company's borrowing base utilization, between 2.00% and 3.00% per annum. At June 30, 2015 and 2014, the weighted average interest rate was 2.9% and 2.8%, respectively.

        In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.500% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

10. Long-Term Debt (Continued)

        The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent, acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations.

        Under the terms of the Credit Facility, the Company is required to repay any amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base or grant liens on additional property having sufficient value to eliminate such excess. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent's notice regarding such borrowing base reduction.

        On March 24, 2015, the Company and Midstates Sub entered into a Sixth Amendment (the "Sixth Amendment") to the Credit Facility. The Sixth Amendment amended the required ratio of net consolidated indebtedness to EBITDA under the Credit Agreement for each of the fiscal quarters in 2015 from 4.0:1.0 to 4.5:1.0. Additionally, the Sixth Amendment amended the mortgage requirements under the Credit Facility to provide for an increase from 80% to 90% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

        On May 21, 2015, the Company and Midstates Sub entered into a Seventh Amendment (the "Seventh Amendment") to the Credit Facility. The Seventh Amendment provided that, with the completion of the offering of the Second Lien Notes and Third Lien Notes (both discussed below), the Company's borrowing base would be reduced to approximately $252.4 million. The Seventh Amendment also eliminated the required ratio of net consolidated indebtedness to EBITDA covenant and added a ratio of Total Senior Indebtedness (as defined therein) to EBITDA of not more than 1.0:1.0, which is further discussed below under "—Debt Covenants." The next scheduled redetermination of the borrowing base is October 2015.

2020 Senior Notes

        On October 1, 2012, the Company issued $600 million in aggregate principal amount of 2020 Senior Notes conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the "Securities Act"). In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2020 Senior Notes rank pari passu in right of payment with the 2021 Senior Notes, the Second Lien Notes and Third Lien Notes. The 2020 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The indenture governing the 2020 Senior Notes (the "2020 Senior Notes Indenture") does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

        At any time prior to October 1, 2015, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020 Senior Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

10. Long-Term Debt (Continued)

October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the 2020 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2020 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2020 Senior Notes redeemed, up to the redemption date.

        Upon the occurrence of certain change of control events, as defined in the 2020 Senior Notes Indenture, each holder of the 2020 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder's 2020 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

        On May 21, 2015 and June 2, 2015, a total of approximately $306.4 million of 2020 Senior Notes were exchanged for Third Lien Notes, as discussed above. The estimated fair value of the 2020 Senior Notes as of June 30, 2015 was $121.1 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

2021 Senior Notes

        On May 31, 2013, the Company issued $700 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes, Second Lien Notes and Third Lien Notes. The 2021 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The indenture governing the 2021 Senior Notes (the "2021 Senior Notes Indenture") does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

        Prior to June 1, 2016, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of any equity offerings at a redemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the 2021 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to, the redemption date. On or after June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2021 Senior Notes redeemed, up to, the redemption date.

        Upon the occurrence of certain change of control events, as defined in the 2021 Senior Notes Indenture, each holder of the 2021 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder's 2021 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

10. Long-Term Debt (Continued)

        On May 21, 2015 and June 2, 2015, a total of approximately $352.3 million of 2021 Senior Notes were exchanged for Third Lien Notes, as discussed above. The estimated fair value as of June 30, 2015 of the 2021 Senior Notes was $137.8 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

Second Lien Notes

        On May 21, 2015, the Company and Midstates Sub issued and sold $625.0 million aggregate principal amount of Second Lien Notes in a private placement conducted pursuant to Rule 144A under the Securities Act. The Second Lien Notes mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company's Credit Facility (including any extension or refinancing of such facility). The Second Lien Notes have an interest rate of 10.0% and interest is payable semi-annually on June 1 and December 1 of each fiscal year. The Second Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company's future restricted subsidiaries (the "Guarantors") and will be initially secured by second-priority liens on substantially all of the Company's and Guarantors' assets that secure the Company's Credit Facility.

        On May 21, 2015, in connection with the offering of Second Lien Notes, the Company and Midstates Sub entered into a registration rights agreement with the initial purchasers of the Second Lien Notes pursuant to which the Company and Midstates Sub are obligated, within 270 days after the issuance of the Second Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Second Lien Notes for substantially identical registered new notes. The Company will be obligated to pay liquidated damages consisting of additional interest on the Second Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

        The Second Lien Notes are senior secured obligations of the Company and rank effectively junior to its obligations under the Credit Facility, effectively senior to its existing and future unsecured indebtedness, effectively senior to the Company's Third Lien Notes and all future junior lien obligations, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Second Lien Notes, pari passu with all of the Company's existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior to any existing or future subordinated debt.

        Upon the occurrence of certain change of control events, as defined in the indenture governing the Second Lien Notes, each holder of the Second Lien Notes will have the right to require that the Company repurchase all or a portion of such holder's 2020 Second Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

        The estimated fair value of the Second Lien Notes was $601.6 million as of June 30, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

Third Lien Notes

        On May 21, 2015 and June 2, 2015, the Company issued approximately $504.121 million and $20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement and in exchange for an aggregate $306.4 million of the 2020 Senior Notes and $352.3 million of the

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

10. Long-Term Debt (Continued)

2021 Senior Notes. The Third Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Guarantors. The Third Lien Notes are secured by third-priority liens on substantially all of the Company's assets that secure the Credit Facility. The Third Lien Notes have an interest rate of 12.0%, consisting of cash interest of 10.0% and paid-in-kind interest of 2.0%, per annum and mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company's Credit Facility (including any extension or refinancing of such facility). Interest is payable semi-annually on June 1 and December 1 of each fiscal year.

        On May 21, 2015, in connection with the issuance of the Third Lien Notes, the Company entered into a registration rights agreement with the initial purchasers of the Third Lien Notes pursuant to which the Company is obligated, within 270 days after the issuance of the Third Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Third Lien Notes for substantially identical registered new notes. The Company will be obligated to pay liquidated damages consisting of additional interest on the Third Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

        The Third Lien Notes are senior secured obligations of the Company and rank effectively junior to its obligations under the Credit Facility and Second Lien Notes to the extent of the value of the collateral securing such indebtedness, effectively senior to its existing and future unsecured indebtedness to the extent of the value of the collateral securing the Third Lien Notes, effectively senior to all future junior lien obligations that rank below a third-priority basis to the extent of the value of the collateral securing the Third Lien Notes, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Third Lien Notes, pari passu to all of the Company's existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior in right of payment to any existing or future subordinated debt.

        Upon the occurrence of certain change of control events, as defined in the indenture governing the Third Lien Notes, each holder of the Third Lien Notes will have the right to require that the Company repurchase all or a portion of such holder's Third Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

        The estimated fair value of the Third Lien Notes was $420.3 million as of June 30, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

Debt Covenants

        The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes contain covenants that, among other things, restrict the Company's ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company's affiliates; (vii) consolidate, merge or sell substantially all of the Company's assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts and (x) enter into agreements restricting the ability of the Company's current and any future subsidiaries to pay dividends.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

10. Long-Term Debt (Continued)

        Additionally, the Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of Total Senior Indebtedness to EBITDA (as defined therein) of not more than 1.0:1.0 and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Credit Facility also limits the Company's ability to make any dividends, distributions or redemptions. The Company was in compliance with all debt covenants at June 30, 2015.

Cross Default Provisions

        The Company's debt facilities contain significant cross default and/or cross acceleration provisions where a default under the Credit Facility or one of the indentures could enable the lenders of the other debt to also declare events of default and accelerate repayment of the obligations under those debt instruments. In general, these cross default/cross acceleration provisions are as follows:

•

The Credit Facility allows the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is the result of the failure to make any payment when due in respect of other indebtedness having an aggregate principal amount of at least 5% of the then effective borrowing base and such failure continues after the applicable grace or notice period; or (ii) is the result of a failure to perform any condition, covenant or other event and such failure permits the holders of such other indebtedness to cause the acceleration of such other indebtedness.



•

The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes allow the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is caused by a failure to make any payment of principal prior to the expiration of the grace period following the final maturity date of such indebtedness; or (ii) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other indebtedness with respect to which an event described herein has occurred, aggregates $50.0 million or more.

11. Preferred Stock

Series A Preferred Stock

        In connection with the Company's acquisition of its Mississippian Lime properties, on September 28, 2012, the Company designated 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the "Series A Preferred Stock") with an initial liquidation preference of $1,000 per share and an 8% per annum dividend, payable semiannually at the Company's option in cash or through an increase in the liquidation preference. On March 30, 2015, the Company elected to pay the $13.0 million semi-annual dividend due on that date through an increase in the Series A Preferred Stock liquidation preference to $1,241 per share. Therefore, for the three months ended June 30, 2015, the $7.9 million Series A Preferred Stock dividend, which the Company paid through the adjustment to the liquidation preference, is based upon the estimated fair value of 71,893 common shares that would have been issued had the Series A Preferred Stock dividend for the three months been converted into common shares at a conversion price of $110.00 per share.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

11. Preferred Stock (Continued)

        On September 30, 2015, the Series A Preferred Stock converted into 3,738,424 shares of the Company's common stock at a conversion price of $110.00 per share.

12. Equity and Share-Based Compensation

Share Activity

        The following table summarizes changes in the number of outstanding shares since December 31, 2014:

        The Company's 2012 LTIP (discussed below) allows for the recipients of restricted stock to surrender a portion of their shares upon vesting to satisfy Federal Income Tax ("FIT") withholding requirements. The Company then remits to the IRS the cash equivalent of the FIT withholding liability. Shares surrendered to the Company in this fashion have been treated as treasury shares acquired at a cost equivalent to the related tax liability. These shares are available for future issuance by the Company.

Incentive Units

        At June 30, 2015, 1,099 incentive units were issued and outstanding. These incentive units were issued prior to the Company's initial public offering. In connection with the corporate reorganization that occurred immediately prior to the Company's initial public offering, these incentive units held in the Company were contributed to FR Midstates Interholding, LP ("FRMI") in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI's aggregate capital contributions and investment expenses ("FRMI Profits"). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.

Share-based Compensation

2012 Long Term Incentive Plan

        On April 20, 2012, the Company established the 2012 Long Term Incentive Plan (the "2012 LTIP") and filed a Form S-8 with the SEC, registering 656,343 shares of common stock for future

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

12. Equity and Share-Based Compensation (Continued)

issuance under the terms of the 2012 LTIP. On May 27, 2014, the Company filed a Form S-8 with the SEC, increasing the number of shares available for future issuance under the terms of the 2012 LTIP to 863,843 shares of common stock.

        The 2012 LTIP provides a means for the Company to attract and retain employees, directors and consultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stock ownership or awards, the value of which is tied to the performance of the Company, thereby strengthening their concern for the welfare of the Company and their desire to remain employed.

        The 2012 LTIP provides for the granting of Options (incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the "Awards"). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. As of June 30, 2015 a total of 863,843 common share Awards are authorized for issuance and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

Non-vested Stock Awards

        At June 30, 2015, the Company had 377,556 non-vested shares of restricted common stock to directors, management and employees outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant); however, beginning in 2013, shares granted under the 2012 LTIP to directors are subject to one-year cliff vesting.

        The fair value of restricted stock grants is based on the value of the Company's common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.

        The following table summarizes the Company's non-vested share award activity for the six months ended June 30, 2015:

        Unrecognized expense, adjusted for estimated forfeitures, as of June 30, 2015 for all outstanding restricted stock awards was $6.4 million and will be recognized over a weighted average period of 1.8 years.

        At June 30, 2015, 170,271 shares remain available for issuance under the terms of the 2012 LTIP.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

13. Income Taxes

        The Company has recorded a tax benefit on its year-to-date pre-tax loss. The Company believes this methodology to be more appropriate at this time due to uncertainty in forecasting the annual effective tax rate (or benefit) on 2015 income (or loss) due to previously recorded property impairments and the effects of federal and state valuation allowance adjustments.

        For the six months ended June 30, 2015, the Company's effective tax rate was a benefit of approximately 1.1%. The Company's effective tax rate differs from the federal statutory rate of 35% due to the effect of state income taxes and changes in the valuation allowance. This year, the Company recorded $305.9 million in additional valuation allowance in light of the impairment of oil and gas properties bringing the total valuation allowance to $309.7 million at June 30, 2015. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that the NOLs are realizable except to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

        The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.

14. Net Loss Per Share

        The Company's Series A Preferred Stock has the nonforfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. The Company's nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted loss per share, pursuant to the two-class method. In the calculation of basic loss per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

        The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net income per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented below.

        The following table (in thousands, except per share amounts) provides a reconciliation of net loss to preferred shareholders, common shareholders, and non-vested restricted shareholders for purposes

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

14. Net Loss Per Share (Continued)

of computing net loss per share for the three and six months ended June 30, 2015 and 2014, respectively:

        The aggregate number of common shares outstanding at June 30, 2015 was 7,257,007 of which 377,556 were non-vested restricted shares. The aggregate number of shares of Series A Preferred Stock outstanding at June 30, 2015 was 325,000, each with a liquidation preference of $1,241 representing on an as-converted basis approximately 3,666,549 common shares based upon a conversion price of $110.00 per share, which have been excluded from the weighted average shares outstanding for EPS purposes for the three and six months ended June 30, 2015 due to their anti-dilutive effect.

15. Commitments and Contingencies

Litigation

        The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental authorities or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices.

        The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of the loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

15. Commitments and Contingencies (Continued)

law, the Company's conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company's accruals could have a material effect on its results of operations.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Midstates Petroleum Company, Inc.

Houston, Texas

        We have audited the accompanying consolidated balance sheets of Midstates Petroleum Company, Inc. and subsidiary ("Midstates") as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of Midstates' management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Midstates Petroleum Company, Inc. and subsidiary as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

        The accompanying financial statements have been prepared assuming that Midstates will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, Midstates' projected debt covenant violation and resulting lack of liquidity raise substantial doubt about its ability to continue as a going concern. Management's plans concerning these matters are also discussed in Note 2 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

        As discussed in Note 3 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for the effects of a reverse stock split on August 3, 2015 and restated for the correction of an error in operating and investing cash flows.

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MIDSTATES PETROLEUM COMPANY, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

   

The accompanying notes are an integral part of these consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

   

The accompanying notes are an integral part of these consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY

(See Notes 10 and 11 for Share History)

(In thousands)

   

The accompanying notes are an integral part of these consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

   

The accompanying notes are an integral part of these consolidated financial statements.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements

1. Organization and Business

        Midstates Petroleum Company, Inc., through its wholly-owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas liquids ("NGL") and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC ("Midstates Sub"), which was previously a wholly-owned subsidiary of Midstates Petroleum Holdings LLC ("Holdings LLC"). Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.'s initial public offering, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates Petroleum Company LLC became a wholly-owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. The terms "Company," "we," "us," "our," and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise. The term "Holdings LLC" refers solely to Midstates Petroleum Holdings LLC prior to the corporate reorganization.

        On April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer and sale of 2,760,000 shares of $0.01 par value common stock, which included 600,000 shares of stock sold by the selling shareholders and 360,000 shares of common stock sold by the selling shareholders pursuant to an option granted to the underwriters to cover over-allotments. The Company's sale of the shares in its initial public offering closed on April 25, 2012 and its initial public offering terminated upon completion of the closing.

        The proceeds of the Company's initial public offering, based on the public offering price of $130.00 per share, were approximately $358.8 million. After subtracting underwriting discounts and commissions of $21.5 million and the net proceeds to the selling stockholders of $117.3 million, the Company received net proceeds of approximately $220.0 million from the registration and sale of 1,800,000 common shares (or $213.6 million net of offering expenses paid directly by the Company). The Company used $67.1 million of the net proceeds to redeem convertible preferred units in Holdings LLC, including interest and other charges, and $99.0 million to pay down a portion of the borrowings under its revolving credit facility. The Company used the remaining $47.5 million to fund the execution of its growth strategy through its drilling program. The Company did not receive any of the proceeds from the sale of the 960,000 shares by the selling stockholders. Immediately after the initial public offering and exercise of the over-allotment option granted to the underwriters, First Reserve Midstates Interholding LP and its affiliates owned approximately 41.4% of the Company's outstanding common stock.

        On October 1, 2012, the Company closed on the acquisition of all of Eagle Energy Production, LLC's producing properties as well as its developed and undeveloped acreage primarily in the Mississippian Lime liquids play in Oklahoma and Kansas for $325 million in cash and 325,000 shares of the Company's Series A Preferred Stock with an initial liquidation preference value of $1,000 per share (the "Eagle Property Acquisition"). The Company funded the cash portion of the Eagle Property Acquisition purchase price with a portion of the net proceeds from the private placement of

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

1. Organization and Business (Continued)

$600 million in aggregate principal amount of 10.75% senior unsecured notes due 2020, which also closed on October 1, 2012 ("2020 Senior Notes").

        On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the "Anadarko Basin Acquisition"), before customary post-closing adjustments. The Company funded the purchase price with a portion of the net proceeds from the private placement of $700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, which also closed on May 31, 2013 ("2021 Senior Notes").

        On March 5, 2014, the Company executed a Purchase and Sale Agreement ("PSA") to sell all of its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for net proceeds of $147.7 million in cash (the "Pine Prairie Disposition"). Acreage subject to the transaction did not include acreage and production in the western part of Louisiana in Beauregard or Calcasieu Parishes or other undeveloped acreage held outside the Pine Prairie field. The sale closed on May 1, 2014.

        At December 31, 2014, the Company has oil and gas operations and properties in Oklahoma, Texas and Louisiana and operated the oil and natural gas properties as one reportable segment engaged in the exploration, development and production of oil, natural gas liquids and natural gas. The Company's management evaluated performance based on one reportable segment as there were not significantly different economic or operational environments within its oil and natural gas properties.

        All pro forma and per share information presented in the accompanying consolidated financial statements have been adjusted to reflect the effects of the Company's initial public offering.

2. Liquidity and Capital Resources

        As of December 31, 2014, the Company had available cash of approximately $11 million and availability under the reserve based revolving credit facility (the "Credit Facility") of approximately $90 million. If there is a downward revision in estimates of proved reserves, the borrowing base for the revolving credit facility may be reduced, and as a result, available liquidity will be reduced. As of December 31, 2014, payments due on contractual obligations during the next twelve months are approximately $150 million. This includes approximately $130 million of interest payments on the senior notes and other operating expenses such as fixed drilling commitments and operating leases. The Company expects it will need to complete certain transactions, including management of debt capital structure and potential asset sales, to have sufficient liquidity to satisfy these obligations in the long-term.

Liquidity Sufficiency

        The liquidity outlook has changed since December 31, 2014 primarily as a result of the substantial decrease in oil and gas prices. This has resulted in lower operating cash flows than expected and if commodity prices remain low compared to recent historical prices, will result in future significantly lower levels of operating cash flows as current hedging contracts expire.

        As a result of the commodity price decline and the Company's substantial debt burden, the Company believes that forecasted cash and available credit capacity are not expected to be sufficient to meet commitments as they come due over the next twelve months and that the Company will not be

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

2. Liquidity and Capital Resources (Continued)

able to remain in compliance with current debt covenants unless able to successfully increase liquidity. Additionally, the terms of the Credit Facility and the indentures governing the senior notes require that some or all of the proceeds from certain asset sales be used to permanently reduce outstanding debt which could substantially reduce the amount of proceeds retained, and the covenants in these debt instruments impose limitations on the amount and type of additional indebtedness the Company can incur, which may significantly reduce the ability to obtain liquidity through the incurrence of additional indebtedness. Furthermore, the ability to refinance any of the existing indebtedness on commercially reasonably terms may be materially and adversely impacted by the current conditions in the energy industry and the Company's financial condition.

        The Company is currently pursuing a number of actions including (i) actively managing the debt capital structure, (ii) selling additional assets, (iii) minimizing capital expenditures, (iv) obtaining waivers or amendments from lenders, (v) effectively managing working capital and (vi) improving cash flows from operations. There can be no assurance that sufficient liquidity can be raised from one or more of these actions or that these actions can be consummated within the period needed to meet certain obligations. The interest payment obligations are substantial, and the Company will be required to pay approximately $32 million in interest on the 2020 Senior Notes on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes on each of June 1 and December 1. The Company has obtained a waiver to the Credit Facility waiving any default as a result of delivering an auditors' opinion in connection with the 2014 financial statements that includes a going concern qualification. As the Company pursues the actions mentioned above to increase liquidity, it may need to negotiate additional waivers or amendments to the Credit Facility or indentures to facilitate those actions. There can be no assurance that the lenders or the holders of the senior notes will agree to any amendment or waiver on acceptable terms and if a default occurs, a failure to do so may provide the lenders the opportunity to accelerate the outstanding debt under these facilities and it would be classified as a current liability on the balance sheet.

        The uncertainty associated with the ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about the ability to continue as a going concern. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with the ability to meet obligations as they come due.

Financial Ratio Covenants

        As of December 31, 2014, the ratio of net consolidated indebtedness to EBITDA was 3.7:1.0 and the ratio of current assets to current liabilities was 1.1:1.0. If liquidity concerns are not addressed in the near-term, the Company may breach the leverage covenant of our Credit Facility, in the third quarter of 2015 which currently requires a maximum ratio of net consolidated indebtedness to EBITDA of 4.0:1.0 beginning with the quarter ended March 31, 2015. As of December 31, 2014, the Company was in compliance with the financial ratio covenants included in the Credit Facility.

Borrowing Base Redetermination

        If oil, NGL, natural gas prices remain weak or deteriorate, the borrowing base under the Credit Facility may be reduced. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility exceeding the borrowing base, the

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

2. Liquidity and Capital Resources (Continued)

Company will be required to repay the deficiency within 30 days or in six monthly installments thereafter, at the Company's election. The Company may not have the financial resources to make any mandatory deficiency principal repayments, which could result in an event of default under the Credit Facility.

Cross Default Provisions

        The debt facilities contain significant cross default and/or cross acceleration provisions where a default under the Credit Facility or one of the indentures could enable the lenders of the other debt to also declare events of default and accelerate repayment of the obligations under those debt instruments. In general, these cross default/cross acceleration provisions are as follows:

•

The Credit Facility allows the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is the result of the failure to make any payment when due in respect of other indebtedness having an aggregate principal amount of at least 5% of the then effective borrowing base and such failure continues after the applicable grace or notice period; or (ii) is the result of a failure to perform any condition, covenant or other event and such failure permits the holders of such other indebtedness to cause the acceleration of such other indebtedness.



•

The indentures governing the senior notes allow the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is caused by a failure to make any payment of principal prior to the expiration of the grace period following the final maturity date of such indebtedness; or (ii) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other indebtedness with respect to which an event described herein has occurred, aggregates $50.0 million or more.

Recent Amendments and Waivers

        In March 2015, the Company received a waiver related to the requirement that an unqualified auditors' opinion without an explanatory paragraph in relation to going concern accompany the 2014 financial statements.

3. Summary of Significant Accounting Policies

Basis of Presentation

        The accompanying consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP").

        All intercompany transactions have been eliminated in consolidation. The consolidated financial statements as of and for the year ended December 31, 2014 include the results of the Pine Prairie field from January 1, 2014 through May 1, 2014, the date of disposition. The consolidated financial statements as of and for the year ended December 31, 2013 include the results from the Anadarko Basin Acquisition beginning May 31, 2013. The consolidated financial statements as of and for the year

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

ended December 31, 2012 include the results from the Eagle Property Acquisition beginning October 1, 2012.

Reverse Stock Split

        On August 3, 2015, the Company completed a 1-for-10 reverse stock split of its outstanding common stock. To effect the reverse stock split, the Company filed a Certificate of Amendment to the Company's Restated Certificate of Incorporation, which provides for the reverse stock split and for the corresponding reduction in the Company's authorized capital stock to 100 million shares of common stock, $0.01 par value per share, following the reverse stock split. The conversion prices for the Series A Preferred Stock were automatically adjusted to reflect the reverse stock split. The consolidated financial statements and notes to the consolidated financial statements included in this document give retrospective effect to the reverse stock split for all periods presented.

Correction of Operating and Investing Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

        In the first quarter of 2015, the Company determined that it had incorrectly presented non-cash accrued capital expenditures in its Statements of Cash Flows since December 31, 2012. Management concluded the misstatement was immaterial to previously issued financial statements; however, the Company has elected to correct the cash flow presentation in the accompanying Consolidated Statement of Cash Flows for the years ended December 31, 2014, 2013 and 2012, as shown in the table below. There is no impact to the Consolidated Balance Sheets as of December 31, 2014 and 2013, or the Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012.

Use of Estimates

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

        Significant estimates include, but are not limited to, the amount of recoverable oil and natural gas reserves; future cash flows from oil and natural gas properties; the fair value of commodity derivative

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

contracts; the fair value of share-based compensation; and the valuation of future asset retirement obligations.

Cash and Cash Equivalents

        The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

        Accounts receivable are stated at the historical carrying amount net of allowance for uncollectible accounts. The carrying amount of the Company's accounts receivable approximate fair value because of the short-term nature of the instruments. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2014 and 2013, the Company had no allowance for doubtful accounts.

Financial Instruments

        The Company's financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivative contracts. Commodity derivative contracts are recorded at fair value (see Note 4). Based upon recent amendments to the Company's Credit Facility, the Company believes the carrying amount of the related floating-rate debt approximates fair value due to the variable nature of the interest rate and the current secured financing terms available to the Company. See fair value discussion of Senior Notes and Series A Preferred Shares issued in October 2012 in Notes 9 and 10, respectively. The carrying amount of the Company's other financial instruments approximate fair value because of the short term nature of the items or variable pricing.

        Derivative financial instruments are recorded in the consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative's fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recorded in "Gains (losses) on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operating activities.

Other Noncurrent Assets

        At December 31, 2014 and 2013, other noncurrent assets consisted of the following:

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

        During the year ended December 31, 2014, the Company has recorded approximately $5.9 million in adjustments to field equipment inventory, either as a result of physical inventory counts, disposals or market adjustments; this is offset by additional inventory added during the period of approximately $1.8 million. For the years ended December 31, 2014 and 2013, the Company recorded $4.1 million and $0.6 million, respectively, of losses on sale of, or market value adjustments to, field equipment inventory.

Property and Equipment

Oil and Gas Properties

        The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company's reserve quantities are sold that results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income.

Unevaluated Property

        Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. Based on current pricing and current drilling plans, we impaired the remaining Anadarko Basin unevaluated property to the full cost pool during the fourth quarter of 2014.

Oil and Gas Reserves

        Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (FASB), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.

        Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Impairment of Oil and Gas Properties/Ceiling Test

        The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this "ceiling." The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. For the year ended December 31, 2014, an impairment of oil and gas properties of $83.5 million, after tax, was recorded. For the year ended December 31, 2013, capitalized costs exceeded the ceiling and an impairment of oil and gas properties of $319.6 million, after tax, was recorded.

        The most significant factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool and negative reserve revisions in certain areas.

        During 2014, the Company transferred $59.2 million of Mississippian unevaluated property costs to the full cost pool. These costs were attributable to leases that either expired during 2014, were determined to not be prospective, or that were assigned proved reserves to previously unproved acreage as a result of the Company's development drilling activities. The Company also transferred $128.2 million of Anadarko Basin and $16.5 million of Gulf Coast unevaluated property costs based up on our lack of plans for further evaluation or development of those leases in the current commodity price environment.

        During 2013, the Company transferred $61.2 million of Gulf Coast unevaluated property costs to the full cost pool based upon our lack of future plans for further evaluation or development of those leases and $168.4 million of Mississippian unevaluated property costs attributable to leases that expired during 2013 or that were assigned to proved reserves as a result of the Company's drilling activities. The Company also transferred $89.6 million of Anadarko Basin unevaluated costs due primarily to lease expirations and development drilling. The negative reserve revisions in our Gulf Coast area were mainly attributable to variability in well performance, our decision during the second quarter of 2013 to halt further development in our West Gordon field and unfavorable cost revisions. See Note 6.

Depreciation, Depletion, and Amortization (DD&A)

        DD&A of oil and gas properties is calculated using the Units of Production Method (UOP). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reserves are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

property costs net of accumulated DD&A, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value.

Capitalized Interest

        Interest from external borrowings is capitalized on unevaluated properties using the weighted-average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at the first production from the field. Capitalized interest is depleted over the useful lives of the assets in the same manner as the depletion of the underlying assets. The Company paid cash interest of $141.9 million, $104.3 million, and $7.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Other Property and Equipment

        Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets, which primarily range from three to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

Accrued Liabilities

        At December 31, 2014 and 2013, accrued liabilities consisted of the following:

Asset Retirement Obligations

        The legal obligations associated with the retirement of long-lived assets are recognized at estimated fair value at the time that the obligation is incurred.

        Oil and gas producing companies incur such a liability upon acquiring or drilling a well. The Company estimates the fair value of an asset retirement obligation in the period in which the obligation is incurred and can be reliably measured. The corresponding asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, any adjustment is recorded in the full cost pool. See Note 8.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

Share-Based Compensation

        We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense, net of amounts capitalized to oil and gas properties, in "General and administrative expense" in our consolidated statements of operations. See Note 11.

Revenue Recognition

        Oil, NGLs and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and collection of the revenues is reasonably assured. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

        The Company follows the sales method of accounting for oil and gas revenues, whereby revenue is recognized for all oil and gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31, 2014 or 2013.

Acquisition and Transaction Costs

        Acquisition and transaction related costs are expensed as incurred and as services are received. Such costs include finders' fees; advisory, legal, accounting, valuation and other professional and consulting fees; and acquisition related general and administrative costs. Costs incurred in 2014 relate to the Pine Prairie Disposition, costs incurred in 2013 relate to the Anadarko Basis Acquisition, and costs incurred in 2012 relate to the Eagle Property Acquisition. See Note 7.

Income Taxes

        Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.

        The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-than-likely-than-not recognition threshold are recognized.

        Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's initial public offering, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets and liabilities differed at

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company's oil and natural gas properties. See Note 12.

Earnings (Loss) Per Share

        Basic earnings (loss) per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings (loss) per common share is calculated by dividing net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options (if any) using the treasury method, as well as the Company's Series A Preferred Stock using the if-converted method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 13.

Recent Accounting Pronouncements

        The Company reviewed recently issued accounting pronouncements that became effective during the twelve months ended December 31, 2014, and determined that none would have a material impact on the Company's consolidated financial statements with the exception of ASU 2014-09, "Revenue from Contracts with Customers" and ASU 2014-15, "Presentation of Financial Statements—Going Concern," (both effective for annual reporting periods beginning after December 15, 2016), which the Company is still evaluating.

4. Fair Value Measurements of Financial Instruments

        The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy:

Level 1—Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2—Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are commodity derivative contracts with fair values based on inputs from actively quoted markets. The Company uses a discounted cash flow approach to estimate the fair values of its commodity derivative contracts, utilizing commodity futures price strips for the underlying commodities provided by a reputable third-party.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurements of Financial Instruments (Continued)

Level 3—Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

        Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

        Derivative Instruments—Commodity derivative contracts reflected in the consolidated balance sheets are recorded at estimated fair value. At December 31, 2014 and 2013, all of the Company's commodity derivative contracts were with seven counterparties, respectively, and are classified as Level 2.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

4. Fair Value Measurements of Financial Instruments (Continued)

        Derivative instruments listed above are presented gross and include collars and swaps that are carried at fair value. The Company records the net change in the fair value of these positions in "Gains (losses) on commodity derivative contracts—net" in the Company's consolidated statements of operations. See Note 5 for additional information on the Company's derivative instruments and balance sheet presentation.

5. Risk Management and Derivative Instruments

        The Company's production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil, NGLs and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGLs and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its oil, NGLs and natural gas production.

        Inherent in the Company's portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company's counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

5. Risk Management and Derivative Instruments (Continued)

financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company's counterparties failed to perform under existing commodity derivative contracts, the maximum loss at December 31, 2014 would have been approximately $126.7 million.

Commodity Derivative Contracts

        As of December 31, 2014, the Company had the following open commodity positions:

Balance Sheet Presentation

        The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

5. Risk Management and Derivative Instruments (Continued)

and qualify for net presentation in the Company's consolidated balance sheets at December, 2014 and 2013, respectively (in thousands):

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

5. Risk Management and Derivative Instruments (Continued)

Gains/Losses on Commodity Derivative Contracts

        The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in "Gains (losses) on commodity derivative contracts—net" within revenues in the consolidated statements of operations. Realized gains and losses represent the actual settlements under commodity derivative contracts that require making a payment to or receiving a payment from the counterparty, as well as any deferred premiums payable to the counterparty upon contract settlement. During the year ended December 31, 2012, the Company paid deferred premiums of $3.3 million related to put options covering a total of 549,000 barrels of crude oil, respectively. No such payments for deferred premiums were made during 2014 or 2013.

        The following table presents realized net losses and unrealized net gains (losses) recorded by the Company in "Gains (losses) on commodity derivative contracts—net" related to the change in fair value of the commodity derivative instruments for the periods presented:

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

6. Property and Equipment

        The Company's property and equipment as of December 31, 2014 and 2013 was as follows (in thousands):

        For the years ended December 31, 2014, 2013 and 2012, depletion expense related to oil and gas properties was $266.8 million, $248.2 million and $125.1 million, respectively and $22.75, $28.42 and $34.17 per barrel of oil equivalent ("Boe"), respectively. For the years ended December 31, 2014, 2013 and 2012, depreciation expense related to other property and equipment was $3.1 million, $2.2 million and $0.5 million, respectively.

        For the years ended December 31, 2014, 2013 and 2012, interest capitalized to unevaluated properties was $12.4 million, $32.2 million and $11.2 million, respectively. For the years ended December 31, 2014, 2013 and 2012, the Company capitalized $12.4 million, $8.4 million and $1.5 million, respectively, of internal costs to oil and gas properties, including $2.2 million, $1.4 million and $0.2 million, respectively, of qualifying share based compensation expense (see Note 11).

7. Acquisition and Divestitures of Oil and Gas Properties

Pine Prairie Disposition

        On March 5, 2014, the Company executed a PSA to sell all of its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, subject to standard post-closing adjustments. Acreage subject to the transaction did not include acreage and production in the western part of Louisiana in Beauregard and Calcasieu Parishes or other undeveloped acreage held outside the Pine Prairie field. On May 1, 2014, the Company closed on the sale for net proceeds of $147.7 million, of which $131.0 million was used to reduce amounts outstanding under its revolving credit facility, with the remainder retained for transaction expenses and working capital purposes. The Company reduced the full cost pool subject to amortization by the amount of the net proceeds received and other standard post-closing adjustments. Accordingly, no gain or loss was recognized.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

7. Acquisition and Divestitures of Oil and Gas Properties (Continued)

Exploration Agreement with PetroQuest

        On June 25, 2014, the Company entered into an exploration agreement with PetroQuest Energy LLC ("PetroQuest") with an effective date of May 1, 2014, in which the Company conveyed to PetroQuest an undivided 50% of its right, title and interest in and to the acreage and other interests in the Fleetwood prospect area in Louisiana.

        With the execution of the agreement, PetroQuest paid $3.0 million in cash consideration and in January 2015, PetroQuest paid additional cash of $7.0 million. As further consideration, PetroQuest granted a credit to the Company of an additional non-interest bearing total sum of $14.0 million, to be credited or paid against the Company's share of costs or expenses incurred to develop the prospect area, including but not limited to, all mineral lease acquisition or maintenance costs and all drilling, completion, equipping and facility costs. For any amounts not fully paid on or before December 31, 2015, the Company can elect to take the remaining portion in cash.

        At December 31, 2014, the Company had a receivable of $7.0 million included in "Other accounts receivable," which represented the additional cash the Company subsequently received in January 2015 under the exploration agreement with PetroQuest.

Other Property Divestitures

        During the twelve months ended December 31, 2014, the Company received $1.4 million in cash for the sale of other properties.

Anadarko Basin Acquisition—May 2013

        On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (before customary post-closing adjustments). The Company funded the purchase price of the Anadarko Basin Acquisition with a portion of the net proceeds from the private placement of $700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, which also closed on May 31, 2013.

        The transaction was accounted for using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

7. Acquisition and Divestitures of Oil and Gas Properties (Continued)

        The fair value of, and the allocation to, the assets acquired and liabilities assumed in the Anadarko Basin Acquisition has been finalized and is shown in the following table (in thousands):

        The finalized balances in the table above include immaterial changes to the amounts originally allocated to oil and gas properties. These changes were required to reflect the final consideration paid after adjustment for certain post-closing purchase price amounts.

Eagle Property Acquisition—October 2012

        On October 1, 2012, the Company closed on the Eagle Property Acquisition. The assets acquired include certain interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments. The aggregate purchase price, before adjustments for expenses incurred and revenue received by Eagle from June 1, 2012 through the closing date and other customary post-closing purchase price adjustments, consisted of (a) $325 million in cash and (b) 325,000 shares of Series A Preferred Stock with an initial liquidation preference of $1,000/share. The Company funded the cash portion of the Eagle Property Acquisition purchase price with a portion of the net proceeds from the private placement (which also closed on October 1, 2012) of $600 million in aggregate principal amount of 10.75% senior unsecured notes due October 1, 2020.

        The transaction was accounted for using the acquisition method of accounting. The fair value of, and the allocation to, the assets acquired and liabilities assumed in the Eagle Property Acquisition has been finalized and is shown in the following table (in thousands):

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

7. Acquisition and Divestitures of Oil and Gas Properties (Continued)

Other Property Acquisitions

        On April 1, 2013, the Company exercised preference rights and acquired additional acreage and producing wells in its Gulf Coast region for $3.4 million.

Actual and Pro Forma Impact of Acquisitions—unaudited

        Revenues attributable to the Anadarko Basin Acquisition included in the Company's consolidated statements of operations for the year ended December 31, 2014 and 2013 were $178.9 million and $104.7 million, respectively. Revenues attributable to the Eagle Property Acquisition, included in the Company's consolidated statements of operations for the year ended December 31, 2012 were $28.4 million.

        The following table presents unaudited pro forma information for the Company as if the Eagle Property Acquisition occurred on January 1, 2011 and the Anadarko Basin Acquisition had been completed on January 1, 2012 (in thousands, other than per share amounts):

        The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Eagle Property Acquisition and the Anadarko Basin Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company's consolidated results of operations actually would have been had the Eagle Property Acquisition been completed on January 1, 2011 and if the Anadarko Basin Acquisition had been completed on January 1, 2012. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined Company.

Acquisition and Transaction Expenses

        For the year ended December 31, 2014, acquisition and transaction costs are costs the Company has incurred primarily as a result of the Pine Prairie Disposition and include advisory, legal, accounting, valuation and other professional and consulting fees; and other general and administrative costs. For the year ended December 31, 2014, the Company recorded $4.1 million of such expenses.

        For the year ended December 31, 2013, acquisition and transaction costs are costs the Company has incurred as a result of the Anadarko Basin Acquisition and include advisory, legal, accounting,

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

7. Acquisition and Divestitures of Oil and Gas Properties (Continued)

valuation and other professional and consulting fees; and general and administrative costs. For the year ended December 31, 2013, the Company recorded $11.8 million of such expenses.

        For the year ended December 31, 2012, acquisition and transaction costs are costs the Company has incurred as a result of the Eagle Property Acquisition and include finders' fees; advisory, legal, accounting, valuation and other professional and consulting fees; and acquisition related general and administrative costs. For the year ended December 31, 2012, the Company recorded $14.9 million of such expenses.

8. Asset Retirement Obligations

        For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the asset retirement obligation at inception is capitalized as part of the carrying amount of the related long-lived assets. Asset retirement obligations approximated $21.6 million and $26.3 million as of December 31, 2014 and 2013, respectively. The liability has been accreted to its present value as of December 31, 2014 and 2013. The Company evaluated its wells and determined a range of abandonment dates through 2079. At December 31, 2014, all asset retirement obligations represent long-term liabilities and are classified as such.

        The following table details the change in the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012, respectively (in thousands):

        Revisions during the year ended December 31, 2014 were due primarily to an increase in estimated future abandonment costs based upon higher costs for oilfield services and materials in the Mississippian Lime and Anadarko areas. Revisions during the year ended December 31, 2013 were due to an increase in estimated future abandonment costs based upon higher oilfield service pricing. Revisions during the year ended December 31, 2012 were due to an increase in estimated future abandonment costs for our Gulf Coast wells based upon higher oilfield service pricing and a change in

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

8. Asset Retirement Obligations (Continued)

the Company's approach to site remediation based upon expected environmental and regulatory requirements.

9. Long-Term Debt

        The Company's long-term debt as of December 31, 2014 and 2013 is as follows:

Reserve-based Credit Facility

        As of December 31, 2014, the Company's credit facility consisted of a $750 million Credit Facility with a borrowing base supported by the Company's Mississippian Lime and Anadarko Basin oil and gas assets. On September 30, 2014, the Company entered into an Assignment and Borrowing Base Increase Agreement that increased the borrowing base from $475 million to $525 million. At December 31, 2014, the Company had drawn $435.2 million on the Credit Facility and had outstanding letters of credit obligations totaling $1.4 million.

        The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of the Company's oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon the Company's borrowing base utilization, between 2.00% and 3.00% per annum. At December 31, 2014 and December 31, 2013, the weighted average interest rate was 2.8% and 2.5%, respectively.

        In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

        The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent, acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations.

        Under the terms of the Credit Facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent's notice regarding such borrowing base reduction.

        The Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of net debt to EBITDA (i.e. leverage ratio)

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

9. Long-Term Debt (Continued)

and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Company is required to maintain a leverage ratio of not more than 4.75 to 1.00 for the quarter ended December 31, 2014, and currently 4.00 to 1.00 for each quarter thereafter. The Credit Facility also limits the Company's ability to make any dividends, distributions or redemptions.

        As of December 31, 2014, the Company was in compliance with the current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. The Company's current ratio at December 31, 2014 was 1.1 to 1.0. At December 31, 2014, the Company's leverage ratio was 3.7 to 1.0.

        In March 2015, the Company received a waiver related to the requirement that an unqualified auditors' opinion without an explanatory paragraph in relation to going concern accompany the 2014 financial statements.

        Based upon the recent amendments to the Credit Facility, the Company believes its carrying amount at December 31, 2014 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate and current financing terms available to the Company.

2020 Senior Notes

        On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the "2020 Outstanding Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the "Securities Act"). On October 29, 2013, substantially all of the 2020 Outstanding Notes were exchanged for an equal principal amount of registered 10.75% senior subordinated notes due 2020 pursuant to an effective registration statement on Form S-4 filed on August 30, 2013 under the Securities Act (the "2020 Exchange Notes"). The 2020 Exchange Notes are identical to the 2020 Outstanding Notes except that the 2020 Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used herein, the term "2020 Senior Notes" refers to both the 2020 Outstanding Notes and the 2020 Exchange Notes. The 2020 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

        At any time prior to October 1, 2015, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020 Senior Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, up to, the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, on the 2020 Senior Notes redeemed, up to, the redemption date.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

9. Long-Term Debt (Continued)

        The Indenture contains covenants that, among other things, restrict the Company's ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company's affiliates; (vii) consolidate, merge or sell substantially all of the Company's assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts and (x) enter into agreements restricting the ability of the Company's current and any future subsidiaries to pay dividends.

        Upon the occurrence of certain change of control events, as defined in the Indenture, each holder of the 2020 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder's 2020 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

        The estimated fair value of the 2020 Senior Notes was $327.0 million as of December 31, 2014 (Level 2 in the fair value measurement hierarchy due to the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2020 Senior Notes was approximately 11.1% for the years ended December 31, 2014 and 2013.

2021 Senior Notes

        On May 31, 2013, the Company issued $700 million in aggregate principal amount of 9.25% senior notes due 2021 (the "2021 Outstanding Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. On October 29, 2013, all of the 2021 Outstanding Notes were exchanged for an equal principal amount of registered 9.25% senior subordinated notes due 2021 pursuant to an effective registration statement on Form S-4 filed on August 30, 2013 under the Securities Act (the "2021 Exchange Notes"). The 2021 Exchange Notes are identical to the 2021 Outstanding Notes except that the 2021 Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used herein, the term "2021 Senior Notes" refers to both the 2021 Outstanding Notes and the 2021 Exchange Notes. The proceeds from the offering of $700 million (net of the initial purchasers' discount and related offering expenses) were used to fund the Anadarko Basin Acquisition and the related expenses, to pay the expenses related to an amendment to the Company's revolving credit facility, to repay $34.3 million in outstanding borrowings under the Company's Credit Facility, and for general corporate purposes.

        The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes. The 2021 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

        Prior to June 1, 2016, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes (less the amount of 2021 Senior Notes redeemed pursuant to the preceding paragraph) with the net proceeds of any Equity Offerings at a redemption

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

9. Long-Term Debt (Continued)

price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the 2021 Senior Notes Indenture), if any, up to, the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest and Additional Interest (as defined in the 2021 Senior Notes Indenture), if any, on the 2021 Senior Notes redeemed, up to, the redemption date.

        The terms of the covenants and change in control provisions in the 2021 Senior Notes Indenture are substantially identical to those of the 2020 Senior Notes discussed above.

        The estimated fair value of the 2021 Senior Notes was $357.0 million as of December 31, 2014 (Level 2 in the fair value measurement hierarchy due to the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2021 Senior Notes was approximately 9.6% and 9.5% for the years ended December 31, 2014 and 2013, respectively.

10. Preferred Stock/Units

Series A Preferred Stock

        At December 31, 2014, the Company had 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the "Series A Preferred Stock") issued and outstanding. In connection with the Eagle Property Acquisition, on September 28, 2012, the Company designated 325,000 shares of Series A Preferred Stock with an initial liquidation preference of $1,000 per share and an 8% per annum dividend, payable semiannually at the Company's option in cash or through an increase in the liquidation preference. The Series A Preferred Shares are convertible after October 1, 2013, in whole but not in part and at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number shares of the Company's common stock calculated by dividing the then-current liquidation preference by the conversion price of $135.00 per share and, if not previously converted, are mandatorily convertible at September 30, 2015 into shares of the Company's common stock at a conversion price no greater than $135.00 per share and no less than $110.00 per share, with the ultimate conversion price dependent upon the volume weighted average price of the Company's common stock during the 15 trading days immediately prior to September 30, 2015. The Series A Preferred Stock was issued on October 1, 2012.

        On September 30, 2015, the Series A Preferred Stock converted into 3,738,424 shares of the Company's common stock at a conversion price of $110.00 per share.

2014

        For the twelve months ended December 31, 2014, the $10.4 million Series A Preferred Stock dividend was based upon the estimated fair value of 265,979 common shares that would have been issued had the notional dividend amounts for the year of $29.3 million been converted into common shares at a conversion price of $110.00 per share.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

10. Preferred Stock/Units (Continued)

2013

        For the twelve months ended December 31, 2013, the $15.6 million Series A Preferred Stock dividend was based upon the estimated fair value of 245,912 common shares that would have been issued had the notional dividend amounts for the year of $27.1 million been converted into common shares at a conversion price of $110.00 per share.

Share Activity

        The following table summarizes changes in the number of Series A Preferred Stock shares since January 1, 2012:

Mandatorily Redeemable Convertible Preferred Units

        In December 2011, Holdings LLC, FR Midstates Holdings LLC ("FR Midstates") and Midstates Petroleum Holdings, Inc. ("Petroleum Inc.") entered into an amended and restated limited liability company agreement, which was later amended in March 2012, to provide for the issuance of up to 65,000, or $65 million in aggregate value, of certain mandatorily redeemable convertible preferred units (the "Preferred Units") between December 15, 2011 and June 10, 2015. During the year ended December 31, 2012, Holdings LLC issued 65,000 Preferred Units to FR Midstates for aggregate cash proceeds of $65.0 million. On April 26, 2012, the Company used $67.1 million of the proceeds from its initial public offering to redeem the Preferred Units in full, including interest and other charges. As such, at December 31, 2012, the Preferred Units are no longer outstanding. The Company recorded $2.1 million related to interest expense associated with these Preferred Units for the year ended December 31, 2012. There was no related interest expense for the years ended December 31, 2014 or 2013.

11. Equity and Share-Based Compensation

Common Shares

        At December 31, 2014, the Company had 7,049,173 and 6,995,705 shares of its common stock issued and outstanding, respectively.

        On April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer and sale of

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

11. Equity and Share-Based Compensation (Continued)

2,760,000 shares of $0.01 par value common stock, which included 600,000 shares of stock sold by the selling shareholders and 360,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments.

        After the corporate reorganization and the completion of its initial public offering discussed above, the Company is authorized to issue up to a total of 100,000,000 shares of its common stock with a par value of $0.01 per share, and 50,000,000 shares of its preferred stock with a par value of $0.01 per share. Holders of the Company's common shares are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and to receive ratably in proportion to the shares of common stock held by them any dividends declared from time to time by the board of directors. The common shares have no preferences or rights of conversion, exchange, pre-exemption or other subscription rights.

        With respect to preferred shares, the Company is authorized, without further stockholder approval, to establish and issue from time to time one or more classes or series of preferred stock with such powers, preferences, rights, qualifications, limitations and restrictions as determined by its board of directors. See discussion of Series A Preferred Shares in Note 10.

Share Activity

        The following table summarizes changes in the number of shares of common stock and treasury stock outstanding shares since January 1, 2012:

Incentive Units.

        At December 31, 2014, 1,099 incentive units were issued and outstanding. In connection with the corporate reorganization that occurred immediately prior to our initial public offering, these incentive

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

11. Equity and Share-Based Compensation (Continued)

units held in the Company were contributed to FR Midstates Interholding, LP ("FRMI") in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI's aggregate capital contributions and investment expenses ("FRMI Profits"). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.

Share-based Compensation

2012 Long Term Incentive Plan.

        On April 20, 2012, the Company established the 2012 Long Term Incentive Plan (the "2012 LTIP") and filed a Form S-8 with the SEC, registering 656,343 shares of common stock for future issuance under the terms of the 2012 LTIP. On May 27, 2014, the Company filed a Form S-8 with the SEC, increasing the number of shares available for future issuance under the terms of the 2012 LTIP to 863,843 shares of common stock.

        The 2012 LTIP provides a means for the Company to attract and retain employees, directors and consultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stock ownership or awards, the value of which is tied to the performance of the Company, thereby strengthening their concern for the welfare of the Company and their desire to remain employed.

        The 2012 LTIP provides for the granting of Options (Incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the "Awards"). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. As of December 31, 2014, a total of 863,843 common share Awards are authorized for issuance under the 2012 LTIP and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

Non-vested Stock Awards.

        At December 31, 2014 the Company had 306,201 shares of restricted common stock outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant), however, beginning in 2013, shares granted under the 2012 LTIP to directors are subject to one-year cliff vesting.

        The fair value of restricted stock grants is based on the value of the Company's common stock on the date of grant. Compensation expense is recognized ratably over the requisite three year service period.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

11. Equity and Share-Based Compensation (Continued)

        The following table summarizes the Company's non-vested share award activity for the years ended December 31, 2014 and 2013:

        Unrecognized expense as of December 31, 2014 for all outstanding restricted stock awards, adjusted for estimated forfeitures, was $10.9 million and will be recognized over a weighted average period of 1.97 years.

        At December 31, 2014, 378,105 shares remain available for issuance under the terms of the 2012 LTIP.

        The share-based compensation costs (net of amounts capitalized to oil and gas properties) recognized as general and administrative expense by the Company for the years ended December 31, 2014, 2013 and 2012 of $8.6 million, $5.7 million and $2.5 million, respectively, all relate to the 2012 LTIP.

        During the quarter ended December 31, 2014, the Company announced that its Houston office would be closing, resulting in accelerated vesting of restricted stock awards in the period for those employees subject to a severance agreement. Of the $8.6 million in share-based compensation for the twelve months ended December 31, 2014, approximately $2.9 million was related to the accelerated vesting for employees impacted by the office closure.

        For the years ended December 31, 2014 and 2013, the Company capitalized $2.2 million and $1.4 million, respectively, of qualifying share-based compensation costs to oil and gas properties.

12. Income Taxes

        Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's initial public offering, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery methodology utilized

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

12. Income Taxes (Continued)

for book and tax purposes for the Company's oil and natural gas properties. In the quarter ended June 30, 2012, the Company recorded a one-time charge to income tax expense of $149.5 million to recognize this deferred tax liability related to the Company's change in tax status caused by the initial public offering.

        The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling and development costs under current law. There is no tax refund available to the Company, nor is there any current federal income tax payable. In light of the impairment of oil and gas properties recorded in the year ended December 31, 2013, Management recorded a $45.7 million valuation allowance against the Company's federal and State of Louisiana NOLs for 2013. Management believed that the balance of the Company's NOLs were realizable only to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment. During the year ended December 31, 2014, the Company recorded unrealized gains on commodity derivative contracts in the amount of $157.5 million, which resulted in pre-tax book income $123.3 million. This activity resulted in the full release of the federal valuation allowance of $39.9 million. The Company continues to report a net valuation allowance of $3.8 million for Louisiana state losses. The Company's NOLs were incurred in the tax years 2012 through 2014. U.S. federal and State of Oklahoma NOLs will generally be available for use through the tax years 2033 and 2034, respectively, and its State of Louisiana NOLs are generally available through 2023 and 2029, respectively. The State of Texas currently has no NOL carryover provision. The Company believes that Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period, will not have an adverse effect on future NOL usage.

        On September 13, 2013, the US Treasury and IRS issued final Tangible Property Regulations ("TPR") under IRC Section 162 and IRC Section 263(a). The regulations are effective for tax years beginning on or after January 1, 2014. Due to these changes, certain portions may require an accounting method change on a retroactive basis, thus requiring a IRC Section 481(a) adjustment related to fixed and real asset deferred taxes. The accounting rules under ASC 740 treat the release of the regulations as a change in tax law as of the date of issuance and require the Company to determine whether there will be an impact on its financial statements for the period ended December 31, 2014. Any such impact of the final tangible property regulations would affect temporary deferred taxes only and result in a balance sheet reclassification within non-current deferred taxes. The Company has analyzed the expected impact of the TPR on the Company and concluded that the expected impact is minimal. The Company will continue to monitor the impact of any future changes to the TPR on the Company prospectively.

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

12. Income Taxes (Continued)

        As of December 31, 2014, the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods. The Company expects $0.6 million in Texas Margins Tax payments in 2015.

        The Company's estimated income tax expense differs from the amount derived by applying the statutory federal rate to pretax income principally due the effect of the following items (in thousands):

        Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

12. Income Taxes (Continued)

income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands):

13. Earnings (Loss) Per Share

        The Company's Series A Preferred Stock issued in connection with the Eagle Property Acquisition has the nonforfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. The Company's nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted earnings (loss) per share, pursuant to the two-class method. In the calculation of basic earnings (loss) per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

13. Earnings (Loss) Per Share (Continued)

dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net income per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented below.

        The following table (in thousands, except per share amounts) provides a reconciliation of net income (loss) to preferred shareholders, common shareholders, and participating securities for purposes of computing net income (loss) per share:

14. Concentrations of Credit Risk

        Financial instruments which potentially subject the Company to credit risk consist primarily of cash balances, accounts receivable and derivative financial instruments.

        The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company.

        The Company normally sells production to a relatively small number of purchasers, as is customary in the exploration, development and production business. The Company typically sells a substantial portion of production under short-term (usually one month) contracts tied to a local index. The Company does not have any long-term, fixed-price sales contracts. For the year ended December 31, 2014, four purchasers accounted for 28%, 18%, 15% and 12% respectively, of the Company's revenue. For the year ended December 31, 2013, five purchasers accounted for 28%, 16%, 13%, 12% and 11%

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

14. Concentrations of Credit Risk (Continued)

respectively, of the Company's revenue. For the year ended December 31, 2012, three purchasers accounted for 41%, 32% and 10%, respectively, of the Company's revenue.

        Substantially all of the Company's accounts receivable result from the sale of oil, natural gas and natural gas liquids. At December 31, 2014, four purchasers accounted for approximately 25%, 23%, 15% and 13% respectively, of the accounts receivable balance. At December 31, 2013, three purchasers accounted for approximately 31%, 16%, and 13%, respectively, of the accounts receivable balance.

        Derivative financial instruments are generally executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. The Company also has netting arrangements in place with counterparties to reduce credit exposure. The Company has not experienced any losses from such instruments.

15. Commitments and Contingencies

Contractual Obligations

        At December 31, 2014, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other contracts are as follows (in thousands):

        For the years ended December 31, 2014, 2013 and 2012, the Company expensed $2.3 million, $1.7 million and $1.1 million, respectively, for office rent.

        In addition to the commitments noted in the above table, the Company is party to a gas transportation, gathering and processing contract (as amended and effective June 1, 2013) in the Mississippian Lime region which includes certain minimum natural gas and NGL volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, the Company would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee of roughly $0.08 to $0.125 per gallon (subject to annual escalation). The NGL volume commitments range

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Consolidated Financial Statements (Continued)

15. Commitments and Contingencies (Continued)

from 2,800 Bbls to 5,780 Bbls per day for each monthly accounting period over the remaining term of the contract. Additionally, the Company is obligated to deliver a total of 38,100,000 MMBtu and 76,200,000 MMBtu during the first 30 months and 60 months of the contract, respectively. During the first 30 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu. During the first 60 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu, provided that the Company would receive volumetric credit for any deficiency payment made after the initial 30 months. The Company is currently delivering at least the minimum volumes required under these contractual provisions and does not expect to incur any future volumetric shortfall payments during the term of this contract.

        Commitments related to ARO's are not included in the table above; see Note 8 for discussion of those commitments.

Litigation

        The Company is involved in disputes or legal actions arising in the ordinary course of its business. The Company may not be able to predict the timing or outcome of these or future claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effect on our financial condition, results of operations or cash flows. Currently, it is not party to any legal proceedings that the Company believes, individually or in the aggregate, are reasonably expected to have a material adverse effect on its financial position, results of operations, or cash flows.

16. Subsequent Events

Sale of Dequincy Assets

        The Company executed a PSA in March 2015 for the sale of its Dequincy assets, its only remaining producing properties in Louisiana, for total consideration of $44 million (subject to customary purchase price adjustments). The PSA includes the ownership interests in developed and undeveloped acreage in the Dequincy area.; the transaction does not include our acreage and interests in the Fleetwood area of Louisiana. The net proceeds from the sale will be used to pay down a portion of the outstanding borrowings under the Company revolving credit facility and for general corporate purposes. The transaction has an effective date of March 1, 2015 and closed on April 21, 2015.

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SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

        The supplemental data presented herein reflects information for all of the Company's oil and natural gas producing activities.

Capitalized Costs

        The following table sets forth the capitalized costs related to the Company's oil and natural gas producing activities at December 31, 2014 and 2013 (in thousands):

        Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

        The following table sets forth costs incurred related to the Company's oil and natural gas activities for the years ended December 31, 2014, 2013 and 2012 (in thousands):

Costs Not Being Amortized

        The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2014, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The evaluation activities are expected to be completed within three to five years.

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Estimated Quantities of Proved Oil and Natural Gas Reserves

        The reserve estimates at December 31, 2014, 2013 and 2012 for the Gulf Coast area and at December 31, 2013 for the Mississippian Lime area were based on a report prepared by Netherland, Sewell and Associates, Inc., independent reserve engineers, in accordance with the FASB's authoritative guidance on oil and gas reserve estimation and disclosures. The reserve estimates at December 31, 2014 for the Mississippian Lime and Anadarko Basin areas and at December 31, 2013 for the Anadarko Basin area were based on reports prepared by Cawley Gillespie & Associates, Inc., independent reserve engineers, in accordance with the FASB's authoritative guidance on oil and gas reserve estimation and disclosures.

        At December 31, 2014, all of the Company's oil and natural gas producing activities were conducted within the continental United States.

        The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

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        The following table sets forth the Company's net proved, proved developed and proved undeveloped reserves at December 31, 2014, 2013 and 2012(1):

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Purchases of Reserves in Place

        In 2014, the Company did not have any additions from purchases of reserves in place.

        In 2013, the Company had a total of 37,642 MBoe of additions from purchases of reserves in place primarily as a result of the Anadarko Basin Acquisition, which closed on May 31, 2013 (see Note 7). The acquired assets included interests in producing oil and natural gas assets and leasehold acreage in Texas and Oklahoma.

        In 2012, the Company had a total of 34,969 MBoe of additions from purchase of reserves in place as a result of the Eagle Property Acquisition would closed on October 1, 2012 (see Note 7). The acquired assets included interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas.

Extensions, Discoveries and Other Additions

        In 2014, the Company had a total of 77,035 MBoe of additions from extensions and discoveries, all of which related to the Mississippian area.

        In 2013, the Company had a total of 43,608 MBoe of additions from extensions and discoveries. Approximately 34,300 MBoe related to the Mississippian area, while the remaining 9,300 MBoe related to the Anadarko Basin and Gulf Coast areas.

        In 2012, the Company had a total of 20,935 MBoe of additions from extensions and discoveries as a result of infill drilling and field delineation activities. Approximately 16,500 MBoe related to the Gulf Coast area, while the remaining 4,400 MBoe related to the Mississippian area. In the Gulf Coast, Pine Prairie had the largest increase with approximately 13,100 MBoe.

Sales of Reserves in Place

        In 2014, the Company had 16,391 MBoe in sales of reserves in place related to the Pine Prairie Disposition, which closed on May 1, 2014.

        There were no sales of reserves during 2013 or 2012.

Revision of Previous Estimates

        In 2014, the Company had net negative revisions of 22,925 MBoe related to proved undeveloped reserves, of which 3,084 MBoe related to reductions in our Gulf Coast area, and 22,138 MBoe related to reductions in our Anadarko Basin area, partially offset by 2,297 MBoe in positive revisions in the Mississippian Lime area. These net negative revisions in the Gulf Coast were primarily due to our lack of future development plans in this area. The net negative revisions in the Anadarko Basin were primarily due to our current drilling plans which did not allow for development of these proved undeveloped reserves within five years of their initial booking.

        In 2013, the Company had net negative revisions of 20,230 MBoe, of which approximately 17,800 MBoe related to the Gulf Coast. Of these revisions in the Gulf Coast, approximately 9,500 MBoe related to Pine Prairie and were driven by higher development and lease operating costs which resulted in certain proved undeveloped locations becoming uneconomic as of December 31, 2013, and approximately 4,900 MBoe related to West Gordon, primarily due to poor drilling results.

        In 2012, the Company had net negative revisions of 2,982 MBoe, of which 1,573 MBoe related to West Gordon.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

        The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.

        Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

        Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties for the years ended December 31, 2014 were $94.99/Bbl for oil, $39.17/Bbl for NGLs and $4.35 per MMBtu for natural gas. The average adjusted product prices weighted by production over the remaining lives of the properties for the years ended December 31, 2013 were $97.18/Bbl for oil, $36.36/Bbl for NGLs and $3.286 for natural gas. The average adjusted product prices weighted by production over the remaining lives of the properties for the years ended December 31, 2012 were $98.64/Bbl for oil, $36.84/Bbl for NGLs and $2.648 for natural gas. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

        The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company's oil and natural gas reserves at December 31, 2014, 2013, and 2012.

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        The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the periods presented.

F-73

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

        The following table presents selected quarterly financial data derived from the Company's unaudited interim financial statements. The following data (in thousands, except per share amounts) is only a summary and should be read with the Company's historical consolidated financial statements and related notes contained in this document.

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ANNEX A:

        LETTER OF TRANSMITTAL

TO TENDER
OLD 10% SENIOR SECURED SECOND LIEN NOTES DUE 2020
OF

MIDSTATES PETROLEUM COMPANY, INC.

AND

MIDSTATES PETROLEUM COMPANY LLC

PURSUANT TO THE EXCHANGE OFFER AND PROSPECTUS
DATED OCTOBER 16, 2015

        The Exchange Agent for the Exchange Offer is Wilmington Trust, National Association, and its contact information is as follows:

By Facsimile (for Eligible Institutions only):
(302) 636-4139
For Information or Confirmation by Telephone:
(302) 636-6470

        If you wish to exchange old 10% Senior Secured Second Lien Notes due 2020 for an equal aggregate principal amount of new 10% Senior Secured Second Lien due 2020 pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the Exchange Agent prior to the Expiration Time.

        We refer you to the Prospectus, dated October 16, 2015 (the "Prospectus"), of Midstates Petroleum Company, Inc. and Midstates Petroleum Company LLC (collectively, the "Issuers") and this Letter of Transmittal (the "Letter of Transmittal"), which together describe the Issuers' offer (the "Exchange Offer") to exchange their 10% Senior Secured Second Lien Notes due 2020 (the "new notes") that have been registered under the Securities Act of 1933, as amended (the "Securities Act"), for a like principal amount of their issued and outstanding 10% Senior Secured Second Lien Notes due 2020 (the "old notes"). Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

        The Issuers reserve the right, at any time or from time to time, to extend the Exchange Offer at their discretion, in which event the term "Expiration Time" shall mean the latest time and date to

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which the Exchange Offer is extended. The Issuers shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Time.

        This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program ("ATOP") of The Depository Trust Company ("DTC") pursuant to the procedures set forth in the Prospectus under the caption "Exchange Offer—Procedures for Tendering." DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent's DTC account. DTC will then send a computer generated message known as an "agent's message" to the Exchange Agent for its acceptance. For you to validly tender your old notes in the Exchange Offer the Exchange Agent must receive, prior to the Expiration Time, an agent's message under the ATOP procedures that confirms that:

•

DTC has received your instructions to tender your old notes; and



•

you agree to be bound by the terms of this Letter of Transmittal.

        BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

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PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

        1.     By tendering old notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

        2.     By tendering old notes in the Exchange Offer, you represent and warrant that you have full authority to tender the old notes described above and will, upon request, execute and deliver any additional documents deemed by the Issuers to be necessary or desirable to complete the tender of old notes.

        3.     You understand that the tender of the old notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between you and the Issuers as to the terms and conditions set forth in the Prospectus.

        4.     By tendering old notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the "SEC"), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1989), Morgan Stanley & Co., Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the new notes issued in exchange for the old notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof without compliance with the registration and prospectus delivery provisions of the Securities Act (other than a broker-dealer who purchased old notes exchanged for such new notes directly from the Issuers to resell pursuant to Rule 144A or any other available exemption under the Securities Act and any such holder that is an "affiliate" of the Issuers within the meaning of Rule 405 under the Securities Act), provided that such new notes are acquired in the ordinary course of such holders' business and such holders are not participating in, and have no arrangement with any other person to participate in, the distribution of such new notes.

        5.     By tendering old notes in the Exchange Offer, you hereby represent and warrant that:

(a)

the new notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of your business, whether or not you are the holder;



(b)

you have no arrangement or understanding with any person to participate in the distribution of old notes or new notes within the meaning of the Securities Act;



(c)

you are not an "affiliate," as such term is defined under Rule 405 promulgated under the Securities Act, of the Issuers; and



(d)

if you are a broker-dealer, that you will receive the new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities and that you acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your old notes registered in the shelf registration statement described in the Registration Rights Agreement, dated as of May 21, 2015 (the "Registration Rights Agreement"), by and among the Issuers and the Initial Purchaser (as defined therein). Such election may be made by notifying the Issuers in writing at Midstates Petroleum Company, Inc., Attention: Scott C. Weatherholt, 321 South Boston Avenue, Suite 1000, Tulsa, Oklahoma 74103, Phone: (918) 947-8550. By making such election, you agree, as a holder of old notes participating in a shelf registration, to indemnify and hold harmless the Issuers, each of the directors of the Issuers, each of the officers of the Issuers who signs such shelf registration statement, each person who controls the Issuers within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and each other holder of old notes, from and against any and all losses, claims, damages or liabilities caused by any untrue

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statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to you furnished in writing by or on behalf of you expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

        6.     If you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, you acknowledge by tendering old notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such new notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an "underwriter" within the meaning of the Securities Act.

        7.     If you are a broker-dealer and old notes held for your own account were not acquired as a result of market-making or other trading activities, such old notes cannot be exchanged pursuant to the Exchange Offer.

        8.     Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives.

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INSTRUCTIONS

FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER

1.     Book-Entry Confirmations.

        Any confirmation of a book-entry transfer to the Exchange Agent's account at DTC of old notes tendered by book-entry transfer (a "Book-Entry Confirmation"), as well as Agent's Message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at one of its addresses set forth herein prior to the Expiration Time.

2.     Partial Tenders.

        Tenders of old notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The entire principal amount of old notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all old notes is not tendered, then old notes for the principal amount of old notes not tendered and new notes issued in exchange for any old notes accepted will be delivered to the holder via the facilities of DTC promptly after the old notes are accepted for exchange.

3.     Validity of Tenders.

        All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered old notes will be determined by the Issuers, in their sole discretion, which determination will be final and binding. The Issuers reserve the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuers, be unlawful. The Issuers also reserve the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any old notes. The Issuers' interpretation of the terms and conditions of the Exchange Offer (including the instructions on the Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as the Issuers shall determine. Although the Issuers intend to notify holders of defects or irregularities with respect to tenders of old notes, neither the Issuers, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in the Letter of Transmittal, promptly following the Expiration Time.

4.     Waiver of Conditions.

        The Issuers reserve the absolute right to waive, in whole or part, up to the expiration of the Exchange Offer, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.

5.     No Conditional Tender.

        No alternative, conditional, irregular or contingent tender of old notes will be accepted.

6.     Request for Assistance or Additional Copies.

        Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent using the contact information set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

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7.     Withdrawal.

        Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption "Exchange Offer—Withdrawal of Tenders."

8.     No Guarantee of Late Delivery.

        There is no procedure for guarantee of late delivery in the Exchange Offer.

        IMPORTANT: BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

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Midstates Petroleum Company, Inc.
Midstates Petroleum Company LLC

Offer to exchange up to

$625,000,000 aggregate principal amount of 10% Senior Secured Second
Lien Notes due 2020 that have been registered under the Securities Act
of 1933

for

$625,000,000 aggregate principal amount of 10% Senior Secured Second
Lien Notes due 2020 that have not been registered under the Securities
Act of 1933

The exchange offer and withdrawal rights will expire at 5:00 p.m.,
New York City time, on November 16, 2015 unless extended.

   

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