Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM 10-K
 
 
 
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-12719
 
  
GOODRICH PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
 
  
Delaware
 
76-0466193
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
801 Louisiana, Suite 700
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)
(Registrant’s telephone number, including area code) (713) 780-9494
Securities Registered Pursuant to Section 12(b) of the Act:
Common Stock, par value $0.01 per share
 
OTC Marketplace
(Title of Each Class)
 
(Name of Each Exchange)
Securities Registered Pursuant to Section 12(g) of the Act:
 
 
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  ý
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes  ¨    No  ý
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
¨
  
Accelerated filer
o
Non-accelerated filer
¨
  
Smaller reporting company
x
Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  ý
The aggregate market value of the Common Stock, par value $0.20 per share, held by non-affiliates (based upon the closing sales price on the OTC Market on June 30, 2016, the last business day of the Predecessor registrant’s most recently completed second fiscal quarter) was approximately $2.3 million. The number of shares of the Successor registrant’s common stock par value $0.01 per share, outstanding as of February 24, 2017 was 9,108,826.
Indicate by check mark whether the Registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes X   No  

Documents Incorporated By Reference:
Certain information called for in Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference to the registrant’s definitive proxy statement for its annual meeting of stockholders, or will be included in an amendment to this Annual Report on Form 10-K.
 



GOODRICH PETROLEUM CORPORATION
ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED
December 31, 2016
 
 
Page
PART I
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
 
 
 
PART IV
 
 
 

2



PART I

Items 1. and 2.
Business and Properties
General
Goodrich Petroleum Corporation, a Delaware corporation (together with its subsidiary, “we,” “our,” or “the Company”) formed in 1995, is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend. We own interests in 156 producing oil and natural gas wells located in 39 fields in eight states. At December 31, 2016, we had estimated proved reserves of approximately 303 Bcfe, comprised of 286 Bcf of natural gas and 2.8 MMBbls of oil and condensate.
We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined by accounting standards related to disclosures about segments of an enterprise.
Voluntary Reorganization under Chapter 11 of the Bankruptcy Code
On April 15, 2016 (the “Petition Date”), we and our subsidiary Goodrich Petroleum Company, L.L.C. (the “Subsidiary”, and together with us, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”), to pursue a Chapter 11 plan of reorganization. The Company filed a motion with the Bankruptcy Court seeking joint administration of the Chapter 11 Cases under the caption In re Goodrich Petroleum Corporation, et al. (Case No. 16-31975). The Debtors received Bankruptcy Court confirmation of their joint plan of reorganization on September 28, 2016 and subsequently emerged from bankruptcy on October 12, 2016. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession for the entire quarter ended September 30, 2016. As such, aspects of the Company’s bankruptcy proceedings and related matters are described below in order to provide context and explain a part of our financial condition and results of operations for the period presented. The Company is accounting for the bankruptcy in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, “Reorganizations”. The Company filed a series of first day motions with the Bankruptcy Court that allowed it to continue to conduct business without interruption. These motions were designed primarily to minimize the impact on the Company’s operations, customers and employees.
Prior to filing the Chapter 11 Cases, on March 28, 2016, the Company entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain holders of the Company’s 8.0% Second Lien Senior Secured Notes due 2018 (the “8.0% Second Lien Notes”) and 8.875% Second Lien Senior Secured Notes due 2018 (the “8.875% Second Lien Notes” and together with the 8.0% Second Lien Notes, the “Second Lien Notes”). The Restructuring Support Agreement set forth, subject to certain conditions, the commitment to and obligations of, on the one hand, the Debtors, and on the other hand, the certain holders, in connection with the restructuring of the Company’s Second Lien Notes, 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), 5.0% Convertible Senior Notes due 2029 (the “2029 Notes”), 5.0% Convertible Senior Notes due 2032 (the “2032 Notes”), 5.0% Convertible Exchange Senior Notes due 2032 (the “2032 Exchange Notes”), 8.875% Senior Notes due 2019 (“the 2019 Notes”), 5.375% Series B Cumulative Convertible Preferred Stock (“Series B Preferred Stock”), 10% Series C Cumulative Preferred Stock (“Series C Preferred Stock”), 9.75% Series D Cumulative Preferred Stock (“Series D Preferred Stock”), 10% Series E Cumulative Convertible Preferred Stock (“Series E Preferred Stock”) and the Company’s common stock, par value $0.20 per share, pursuant to the Company’s Joint Prepackaged Plan of Reorganization filed under Chapter 11 of the United States Bankruptcy Code on the Petition Date. On May 21, 2016, the Restructuring Support Agreement was terminated automatically pursuant to its terms as an Assumption Order approving the Restructuring Support Agreement was not entered by the Bankruptcy Court within thirty-five days of the Petition Date. See discussion on the Company’s Joint Prepackaged Plan of Reorganization below.
The Chapter 11 Cases described above constituted an event of default that accelerated the Company’s obligations under all of its outstanding debt instruments. The agreements governing the Company’s debt instruments at the time provided that as a result of the Bankruptcy Petitions, the principal and interest due thereunder was immediately due and payable. However, any efforts to enforce such payment obligations under the Company’s debt instruments were automatically stayed as a result of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
On April 18, 2016, the Bankruptcy Court issued certain additional interim and final orders with respect to the Debtors’ first-day motions and other operating motions that allowed the Debtors to operate their businesses in the ordinary course. Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or

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stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim were enjoined.
During the Chapter 11 Cases, the Company conducted normal business activities and was authorized to continue to pay and has paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders, critical vendors and other third parties, such as royalty holders and partners.

On July 25, 2016 the Company entered into and filed a motion with the Bankruptcy Court to approve a commitment letter (the “Commitment Letter”) with a group of investors for the new issuance of 13.50% Convertible Second Lien Senior Secured Notes in the initial aggregate principal amount of $40.0 million (the “Convertible Second Lien Notes”). The Bankruptcy Court approved the motion on August 4, 2016 which allowed the Company to submit a revised plan of organization to the Bankruptcy Court. The approval by the Bankruptcy Court of the Commitment Letter terminated the bid procedures that were previously approved by the Bankruptcy Court on July 1, 2016.
Commitment Letter
The Commitment Letter provided for the issuance of $40.0 million in Convertible Second Lien Notes that mature on the later of August 30, 2019 or six months after the maturity of the Exit Credit Agreement (including all amendments, the “Exit Credit Facility”). Interest on the Convertible Second Lien Notes will accrue at a rate of 13.50% per annum and be paid quarterly in cash or paid in kind by adding to the principal at the option of the issuer. The Convertible Second Lien Notes will convert at the option of the purchaser into a number of common shares equal to 15% of the common shares of the reorganized company. Upon closing, purchasers of the Convertible Second Lien Notes (i)were issued 10-year costless warrants for common stock equal to 20% of the common shares of the reorganized company, (ii) took a second priority lien on all assets of the reorganized company, and (iii) received the right to appoint two members to the Board of Directors (the “Board”) of the reorganized company. A total of $20.0 million in proceeds from the issuance of the Convertible Second Lien Notes were used to repay amounts outstanding under the existing Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”) and $20.0 million in proceeds will be used to fund the Company’s Haynesville Shale Trend drilling program.
Plan of Reorganization
The significant features of the Plan of Reorganization (the “Plan of Reorganization”) confirmed by the Bankruptcy Court are as follows:

1.
Each holder of an allowed priority claim (other than a priority tax claim or administrative claim) received either: (a) cash equal to the full allowed amount of its claim or (b) such other treatment as may otherwise be agreed to by such holder, the Debtors, the holders of at least 50% in principal amount of the Second Lien Notes (the “Majority Consenting Noteholders”), and the purchasers of the new Convertible Second Lien Notes (“New 2L Notes Purchasers”);

2.
Each holder of a secured claim (other than a priority tax claim, Senior Credit Facility claim, or Second Lien Notes claim) received, at the Debtors’ election and with the consent of the Majority Consenting Noteholders, either: (a) cash equal to the full allowed amount of its claim, (b) reinstatement of such holder’s claim, (c) the return or abandonment of the collateral securing such claim to such holder, or (d) such other treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders, and the New 2L Notes Purchasers;

3.
The Senior Credit Facility claims were paid cash in an amount sufficient to reduce the Senior Credit Facility claims to a balance of $20.0 million while the remaining $20.0 million owed was to be refinanced into a new senior secured term loan credit facility;


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4.
The Second Lien Notes claims were deemed allowed in the aggregate amount of $175.0 million of principal plus accrued and unpaid interest through the Petition Date. Except to the extent a holder of a Second Lien Note claim agreed in writing to less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Second Lien Notes claim, each holder of a Second Lien Notes claim received their pro rata share of 98% of the new equity interests in the reorganized company (the “New Equity Interests”), subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million;

5.
Holders of unsecured notes claims received, pro rata with holders of other general unsecured claims, their pro rata share of the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million; plus its pro rata share of 2% of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal of $230.0 million;

6.
Holders of allowed general unsecured claims had the option to elect on their ballot to (a) receive, pro rata with holders of unsecured notes claims, its pro rata share of the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million; plus its pro rata share of 2% of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million, or (b) treat its allowed general unsecured claim as a convenience class claim by releasing any claims in excess of $10,000;

7.
Holders of convenience class claims received either: (a) cash equal to the full allowed amount of such holder’s claim or (b) such lesser treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders and the New 2L Notes Purchasers;

8.
Equity interests in the Subsidiary were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Subsidiary did not receive any distribution or retain any property on account of such equity interest in the Subsidiary. Equity interests in the Company were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Company did not receive any distribution or retain any property on account of such equity interest in the Company.

The Company's Plan of Reorganization was confirmed by the Bankruptcy Court on September 28, 2016 and we emerged from bankruptcy on October 12, 2016 (the "Effective Date").

All references made to “Successor” or “Successor Company” relate to Goodrich on and subsequent to the Effective Date. References to the “Successor 2016 Period” relate to the period from October 13, 2016 to December 31, 2016. References to “Predecessor” or “Predecessor Company” refer to Goodrich prior to the Effective Date. References to the “Predecessor 2016 Period” relate to the period from January 1, 2016 to October 12, 2016.
Available Information
Our principal executive offices are located at 801 Louisiana Street, Suite 700, Houston, Texas 77002.
Our website address is http://www.goodrichpetroleum.com. We make available, free of charge through the Investor Relations portion of our website, our annual reports on Form 10-K, proxy statement, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). Reports of beneficial ownership filed pursuant to Section 16(a) of the Exchange Act are also available on our website. Information contained on our website is not part of this report.

5



We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
As used herein, the following terms have specific meanings as set forth below:
 
Bbls
Barrels of crude oil or other liquid hydrocarbons
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
Boe
Barrel of crude oil or other liquid hydrocarbons equivalent
MBbls
Thousand barrels of crude oil or other liquid hydrocarbons
Mboe
Thousand barrels of crude oil equivalent
Mcf
Thousand cubic feet of natural gas
Mcfe
Thousand cubic feet equivalent
MMBbls
Million barrels of crude oil or other liquid hydrocarbons
MMBtu
Million British thermal units
Mmcf
Million cubic feet of natural gas
Mmcfe
Million cubic feet equivalent
MMBoe
Million barrels of crude oil or other liquid hydrocarbons equivalent
NGL
Natural gas liquids
U.S.
United States
Crude oil and other liquid hydrocarbons are converted into cubic feet of natural gas equivalent based on six Mcf of natural gas to one barrel of crude oil or other liquid hydrocarbons.
Developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.
Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.
Dry hole is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically producible as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil-and-natural gas producing activities.
Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.
Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and natural gas lease or license assigns the working interest or a portion thereof to another party who desires to drill on the leased or licensed acreage. Generally, the assignee is required to drill one or more wells to earn its interest in the acreage. The assignor (the “farmor”) usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in”, while the interest transferred by the assignor is a “farm-out”.
Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. The SEC provides a complete definition of field in Rule 4-10 (a) (15).
Gross well or acre is a well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest.

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Net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions of whole numbers.
PV-10 is the pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying the 12-month average price for the year and holding that price constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). PV-10 is not a financial measure that is in accordance with US GAAP.  The SEC methodology for computing the 12-month average price is discussed in the definition of “Proved reserves” below.
Productive well is an exploratory, development or extension well that is not a dry well.
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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. As used in this definition, “existing economic conditions” include prices and costs at which economic producibility from a reservoir is to be determined. The prices shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10 (a) (22) of Regulation S-X.
Reasonable certainty means a high degree of confidence that the quantities will be recovered, if deterministic methods are used. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease. The deterministic method of estimating reserves or resources uses a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation. The probabilistic method of estimation of reserves or resources uses the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.
Undeveloped reserves are proved 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. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can 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 the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover is a series of operations on a producing well to restore or increase production.


8



Oil and Natural Gas Operations and Properties
As of December 31, 2016, nearly all of our proved oil and natural gas reserves were located in Louisiana, Texas and Mississippi. We spent substantially all of our 2016 capital expenditures of $6.3 million in these areas, with $1.5 million, or 24%, spent on the TMS and $4.1 million, or 65% spent on the Haynesville Shale Trend. Our total capital expenditures, including accrued costs for services performed during 2016, consisted of $5.8 million for drilling and completion costs, and $0.5 million for leasehold acquisitions and extensions.
Beginning in the second half of 2014, commodity prices, particularly oil, began to decline sharply. The decline became precipitous late in the fourth quarter of 2014 and into 2016.  The duration and significant magnitude of this price decline has materially and adversely impacted our results of operations and led to substantial changes in our operating and drilling programs for 2016. As a result, during 2016, we focused on managing our balance sheet to reduce leverage and preserve liquidity during this low commodity price environment.
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9



The table below details our acreage positions, average working interest and producing wells as of December 31, 2016.
  
 
 
 
 
 
Average
Producing
Well
Working
Interest
 
Producing wells at December 31, 2016
 
Acreage
As of December 31, 2016
 
 
Field or Area
Gross
 
Net
 
 
Tuscaloosa Marine Shale Trend
215,077

 
155,682

 
65
%
 
38

Haynesville Shale Trend
47,731

 
23,345

 
35
%
 
89

Eagle Ford Shale Trend
32,430

 
14,148

 

 

Other
33,125

 
7,492

 
17
%
 
29

 
Haynesville Shale Trend
As of December 31, 2016, we have acquired or farmed-in leases totaling approximately 47,700 gross (23,300 net) acres in the Haynesville Shale Trend. During 2016, we added 2 gross (.35 net) wells to production in the Chesapeake operated portion of our acreage position. Our Haynesville Shale Trend drilling activities are located in leasehold areas in East Texas and Northwest Louisiana.
Tuscaloosa Marine Shale Trend
As of December 31, 2016, we have acquired approximately 215,100 gross (155,700 net) lease acres in the TMS, an oil shale play in Southwest Mississippi and Southeast Louisiana. During 2016, we did not conduct any drilling operations and did not add any wells to production. As of December 31, 2016, we had 2 wells waiting on completion operations.
Eagle Ford Shale Trend
As of December 31, 2016, we have acquired or farmed-in leases totaling approximately 32,400 gross (14,100 net) lease acres. As part of our efforts in 2015 to reduce leverage and preserve liquidity, we sold all of our proved reserves in the Eagle Ford Shale Trend and a portion of the associated leasehold. We closed the Eagle Ford Shale Trend sale on September 4, 2015.
Other
As of December 31, 2016, we maintained ownership interests in acreage and/or wells in several additional fields.
See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K for additional information on our recent operations in the TMS, Haynesville Shale Trend and Eagle Ford Shale Trend.

Oil and Natural Gas Reserves
The following tables set forth summary information with respect to our proved reserves as of December 31, 2016 and 2015, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and by Ryder Scott Company (“RSC”) our independent reserve engineers. All of our proved reserves estimates are independently prepared by NSAI and RSC. NSAI prepared the estimates on all our proved reserves as of December 31, 2016 on properties other than those located in the TMS. RSC prepared the estimate of proved reserves as of December 31, 2016 for our TMS properties. Copies of the summary reserve reports of NSAI and RSC as of December 31, 2016 are included as exhibits to this Annual Report on Form 10-K. For additional information see Supplemental Information “Oil and Natural Gas Producing Activities (Unaudited)” to our consolidated financial statements in “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Proved undeveloped reserves were not included in our December 31, 2015 reserve estimates as the sustained decline in oil and natural gas prices raised substantial doubt at the time, about our ability to continue as a going concern and our ability to adequately finance the development of proved undeveloped reserves in the future.
Net proved reserves and the PV10 estimates at December 31, 2016 below, were calculated using flat, twelve month average commodity prices of $42.75 per barrel and $2.48 per Mmbtu.

10




 
 
Proved Reserves at December 31, 2016
 
Developed
Producing
 
Developed
Non-Producing
 
Undeveloped
 
Total
 
(dollars in thousands)
Net Proved Reserves:
 

 
 

 
 

 
 

Oil (MBbls) (1)
1,988

 
827

 

 
2,815

Natural Gas (Mmcf)
23,277

 
4,266

 
258,495

 
286,038

Mcf Natural Gas Equivalent (Mcfe) (2)
35,207

 
9,225

 
258,495

 
302,927

Estimated Future Net Cash Flows
 

 
 

 
 

 
$
159,824

PV-10 (3)
 

 
 

 
 

 
$
57,086

Discounted Future Income Taxes
 

 
 

 
 

 
(164)

Standardized Measure of Discounted Net Cash Flows (3)
 

 
 

 
 

 
$
56,922

 
 
 
 
 
 
 
 
 
Proved Reserves at December 31, 2015
 
Developed
Producing
 
Developed
Non-Producing
 
Undeveloped
 
Total
 
(dollars in thousands)
Net Proved Reserves:
 

 
 

 
 

 
 

Oil (MBbls) (1)
3,184

 
650

 

 
3,834

Natural Gas (Mmcf)
29,633

 
2,218

 

 
31,851

Mcf Natural Gas Equivalent (Mcfe) (2)
48,737

 
6,118

 

 
54,855

Estimated Future Net Cash Flows
 

 
 

 
 

 
$
94,811

PV-10 (3)
 

 
 

 
 

 
$
69,895

Discounted Future Income Taxes
 

 
 

 
 

 

Standardized Measure of Discounted Net Cash Flows (3)
 

 
 

 
 

 
$
69,895

 
(1)
Includes condensate.
(2)
Based on ratio of six Mcf of natural gas per Bbl of oil and per Bbl of NGLs.
(3)
PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 of our total year-end proved reserves is considered a non-US GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. See the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.
(4)
The following table presents our reserves by targeted geologic formation in Mmcfe.
 
 
December 31, 2016
Area
Proved
Developed
 
Proved
Undeveloped
 
Proved
Reserves
 
% of
Total
Tuscaloosa Marine Shale Trend
16,796

 

 
16,796

 
6
%
Haynesville Shale Trend
27,260

 
258,495

 
285,755

 
94
%
Other
376

 

 
376

 
%
Total
44,432

 
258,495

 
302,927

 
100
%
 
Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil

11



and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.
In accordance with the guidelines of the SEC, our independent reserve engineers’ estimates of future net revenues from our estimated proved reserves, and the PV-10 and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period of January 2016 through December 2016, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For reserves at December 31, 2016, the average twelve month prices used were $2.48 per MMBtu of natural gas and $42.75 per Bbl of crude. These prices do not include the impact of hedging transactions, nor do they include the adjustments that are made for applicable transportation and quality differentials, and price differentials between natural gas liquids and oil, which are deducted from or added to the index prices on a well by well basis in estimating our proved reserves and related future net revenues.
Our proved reserve information as of December 31, 2016 included in this Annual Report on Form 10-K was estimated by our independent petroleum engineers, NSAI and RSC, in accordance with petroleum engineering and evaluation principles and definitions and guidelines set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserve Information promulgated by the Society of Petroleum Engineers. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Our principal engineer has over 30 years of experience in the oil and natural gas industry, including over 25 years as a reserve evaluator, trainer or manager. Further professional qualifications of our principal engineer include a degree in petroleum engineering, extensive internal and external reserve training, and experience in asset evaluation and management. In addition, the principal engineer is an active participant in professional industry groups and has been a member of the Society of Petroleum Engineers for over 30 years.
Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria is provided to them. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.
We consider providing independent fully engineered third-party estimates of reserves from nationally reputable petroleum engineering firms, such as NSAI and RSC, to be the best control in ensuring compliance with Rule 4-10 of Regulation S-X for reserve estimates.
While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI and RSC reserve reports are reviewed by our senior management with representatives of NSAI and RSC and our internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves semi-annually.
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. To achieve reasonable certainty, NSAI and RSC 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, well logs, geologic maps, available downhole and production data, seismic data and well test data.
Our total proved reserves at December 31, 2016, as estimated by NSAI and RSC, were 302,927 Mmcfe, consisting of 286 Bcf of natural gas and 2.8 MMBbls of oil and condensate. In 2016 we added approximately 264.2 Mmcfe related to our drilling activities in the Haynesville Shale Trend. We had negative revisions of approximately 7.7 Mmcfe, divestitures of 3.0 Mmcfe and produced 8.4 Mmcfe in 2016. We are employing new completion techniques on our Haynesville Shale Trend wells which have been proven on the two successful wells we drilled in 2016. These well results in conjunction with our acreage position and our new financial ability to develop our Haynesville Shale Trend properties allowed us to add the Haynesville Shale Reserves as of December 31, 2016.

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We did not report any proved undeveloped reserves at December 31, 2015, consequently, we did not have any proved undeveloped reserves to convert to proved developed reserves during 2016.
Productive Wells
The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2016:
 
 
Oil
 
Natural Gas
 
Total
 
Gross (1)
 
Net (2)
 
Gross (1)
 
Net (2)
 
Gross (1)
 
Net (2)
Tuscaloosa Marine Shale Trend:
 
 
 
 
 
 
 
 
 
 
 
Southeast Louisiana
17

 
12

 

 

 
17

 
12

Southwest Mississippi
21

 
13

 

 

 
21

 
13

Haynesville Shale Trend:
 

 
 

 
 

 
 

 
 

 
 

East Texas

 

 
6

 
4

 
6

 
4

Northwest Louisiana

 

 
83

 
27

 
83

 
27

Other
10

 
1

 
19

 
4

 
29

 
5

Total Productive Wells
48

 
26

 
108

 
35

 
156

 
61

 
(1)
Royalty and overriding interest wells that have immaterial values are excluded from the above table. As of December 31, 2016, only three wells with royalty-only and overriding interests-only are included.
(2)
Net working interest.
Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline connections. A gross well is a well in which we maintain an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by us equals one. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, four wells had completions in multiple producing horizons.
Acreage
The following table summarizes our gross and net developed and undeveloped acreage under lease as of December 31, 2016. Acreage in which our interest is limited to a royalty or overriding royalty interest is excluded from the table.
 
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Tuscaloosa Marine Shale Trend:
 
 
 
 
 
 
 
 
 
 
 
Southwest Mississippi
23,179

 
19,211

 
53,235

 
26,731

 
76,414

 
45,942

Southeast Louisiana
27,120

 
20,305

 
111,543

 
89,435

 
138,663

 
109,740

Haynesville Shale Trend:
 

 
 

 
 

 
 

 
 

 
 

East Texas
12,578

 
7,502

 
292

 
292

 
12,870

 
7,794

Northwest Louisiana
34,861

 
15,720

 

 

 
34,861

 
15,720

Eagle Ford Shale Trend:
 

 
 

 
 

 
 

 
 

 
 

South Texas

 

 
32,430

 
14,148

 
32,430

 
14,148

Other
28,488

 
6,636

 
4,637

 
687

 
33,125

 
7,323

Total
126,226

 
69,374

 
202,137

 
131,293

 
328,363

 
200,667




Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the remaining primary term of such a lease. The oil and natural gas leases in which we have an interest are for varying

13



primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as oil or natural gas is produced.
Lease Expirations
We have undeveloped lease acreage, excluding optioned acreage, that will expire during the next four years, unless the leases are converted into producing units or extended prior to lease expiration. The following table sets forth the lease expirations as of December 31, 2016:
 
Year
Net Acreage
2017
66,634

2018
22,605

2019
3,801

2020
12,835

 
Operator Activities
We operate a majority of our producing properties by value, and will generally seek to become the operator of record on properties we drill or acquire. Chesapeake Energy Corporation (“Chesapeake”) continues to operate a majority of our jointly owned Northwest Louisiana acreage in the Haynesville Shale Trend.
Drilling Activities
The following table sets forth our drilling activities for the last three years. As denoted in the following table, “gross” wells refer to wells in which a working interest is owned, while a “net” well is deemed to exist when the sum of the fractional working interests we own in gross wells equals one.
 
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development Wells:
 

 
 

 
 

 
 

 
 

 
 

Productive
2

 
0.4

 
8

 
6.7

 
19

 
13.0

Non-Productive

 

 

 

 

 

Total
2

 
0.4

 
8

 
6.7

 
19

 
13.0

Exploratory Wells:
 

 
 

 
 

 
 

 
 

 
 

Productive

 

 

 

 
4

 
3.2

Non-Productive

 

 

 

 

 

Total

 

 

 

 
4

 
3.2

Total Wells:
 

 
 

 
 

 
 

 
 

 
 

Productive
2

 
0.4

 
8

 
6.7

 
23

 
16.2

Non-Productive

 

 

 

 

 

Total
2

 
0.4

 
8

 
6.7

 
23

 
16.2

 
At December 31, 2016, we had 2 gross (1.7 net) development wells waiting to be completed.
Net Production, Unit Prices and Costs
The following table presents certain information with respect to oil and natural gas production attributable to our interests in all of our properties (including two fields which have attributed more than 15% of our total proved reserves as of December 31, 2016), the revenue derived from the sale of such production, average sales prices received and average production costs during each of the years in the three-year period ended December 31, 2016.
 

14



 
Sales Volumes
 
Average Sales Prices (1)
 
 
 
Average
 
Natural
Gas
Mmcf
 
Oil &
Condensate
MBbls
 
Total
Mmcfe
 
Natural
Gas
Mcf
 
Oil &
Condensate
Per Bbl
 
Total
Per Mcfe
 
% of Total Revenue
 
Production
Cost (2)
Per Mcfe
For Year 2016:
 

 
 

 
 

 
 

 
 

 
 

 
 
 
 

TMS

 
473

 
2,837

 
$

 
$
40.81

 
$
6.80

 
34
%
 
$
1.98

Haynesville Shale Trend
5,471

 

 
5,471

 
1.44

 

 
1.44

 
66
%
 
0.48

Other
84

 
3

 
102

 
3.00

 
39.71

 
3.65

 
%
 
3.69

Total
5,555

 
476

 
8,410

 
$
1.47

 
$
40.80

 
$
3.28

 
100
%
 
$
1.02

For Year 2015:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

TMS

 
883

 
5,298

 
$

 
$
49.60

 
$
8.27

 
55
%
 
$
1.36

Haynesville Shale Trend
7,018

 

 
7,018

 
1.67

 

 
1.67

 
15
%
 
0.39

Eagle Ford Shale Trend (3)
776

 
453

 
3,494

 
2.39

 
46.30

 
6.54

 
29
%
 
1.37

Other
190

 

 
190

 
3.58

 

 
3.58

 
1
%
 
4.55

Total
7,984

 
1,336

 
16,000

 
$
1.79

 
$
48.50

 
$
4.94

 
100
%
 
$
0.97

For Year 2014:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

TMS

 
738

 
4,428

 
$

 
$
90.55

 
$
15.09

 
32
%
 
$
1.07

Haynesville Shale Trend
10,176

 
1

 
10,182

 
3.08

 
86.36

 
3.08

 
15
%
 
0.44

Eagle Ford Shale Trend (3)
1,321

 
928

 
6,889

 
5.70

 
89.69

 
13.31

 
44
%
 
1.62

Other
3,483

 
25

 
3,633

 
5.01

 
90.83

 
5.72

 
9
%
 
2.50

Total
14,980

 
1,692

 
25,132

 
$
3.75

 
$
90.08

 
$
8.30

 
100
%
 
$
1.18

 
(1)
Excludes the impact of commodity derivatives.
(2)
Excludes ad valorem and severance taxes.
(3)
We sold our Eagle Ford Shale Trend proved reserves and a portion of the associated leasehold on September 4, 2015.
Oil and Natural Gas Marketing and Major Customers
Marketing. Our natural gas production is sold under spot or market-sensitive contracts to various natural gas purchasers on short-term contracts. Our oil production is sold to various purchasers under short-term rollover agreements based on current market prices.
Customers. Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2016, and 2015 are as follows:
 
 
Year Ended December 31,
 
2016
 
2015
 
Genesis Crude Oil LP
44
%
 
26
%
 
Sunoco, Inc.
30
%
 
17
%
 
Occidental Energy MA
13
%
 
%
 
BP Energy Company
%
 
31
%
 
 
Competition
The oil and natural gas industry is highly competitive. Major and independent oil and natural gas companies, drilling and production acquisition programs and individual producers and operators are active bidders for desirable oil and natural gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than ours, and staffs and facilities substantially larger than us.


15



Seasonality of Business
 
Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
Employees
At February 24, 2017 we had 43 full-time employees in our Houston administrative office and 4 in our field offices, none of whom is represented by any labor union. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection, and well testing.
Regulations
The availability of a ready market for any oil and natural gas production depends upon numerous factors beyond our control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment.  
Environmental and Occupational Health and Safety Matters
General
Our operations are subject to stringent and complex federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these laws and regulations may require the acquisition of permits before drilling or other related activity commences, restrict the type, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling and production activities on certain lands lying within wilderness, wetlands and other protected areas, impose specific health and safety criteria addressing worker protection, and impose substantial liabilities for pollution arising from drilling and production operations. Environmental laws and regulations also impose certain plugging and abandonment and site reclamation requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit 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. Additionally, the trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and, any changes in environmental laws and regulations that result in more stringent and costly well construction, drilling, waste management or completion activities or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business. Environmental laws and regulations change frequently, and there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future.
The following is a summary of the more significant existing environmental laws to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.
Hazardous Substances and Wastes

16



The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred, and companies that disposed or arranged for the disposal of hazardous substances released at the site. Under CERCLA, these persons may be subject to joint and several, strict liabilities for remediation cost at the site, natural resource damages and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We generate materials in the course of our operations that are regulated as hazardous substances.
We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes that impose stringent requirements related to the handling and disposal of non-hazardous and hazardous wastes. Wastes, including drilling fluids and produced water, generated in the exploration or production of oil and natural gas are exempt from classification as hazardous wastes under RCRA. Proposals have been made from time to time to eliminate this exemption, which, if adopted, would cause some of these wastes to be regulated under the more rigorous RCRA hazardous waste standards. For example, in December 2016, the U.S. Environmental Protection Agency (“EPA”) and certain environmental organizations entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. A loss of this RCRA exemption could result in increased costs to us and the oil and gas industry in general to manage and dispose of generated wastes. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes if they have hazardous characteristics.
We currently own or lease, and in the past have owned or leased, properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes and petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties whose treatment and disposal of hazardous substances, wastes and petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to undertake costly site investigations, remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
Water Discharges and Subsurface Injections
The Federal Water Pollution Control Act, as amended, (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) plan requirements imposed under the Clean Water Act 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. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In September 2015, new EPA and U.S. Army Corps of Engineers (the “Corps”) rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. Most recently, in January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction over the challenge to the rule rests with the federal district or appellate courts. Litigation surrounding the rule is ongoing. The process for obtaining permits has the potential to delay the development of natural gas and oil projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements related to the prevention of oil spills into navigable waters as well as liabilities for oil cleanup costs, natural resource damages and a variety of public and private damages that may result from such oil spills.

17



The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended (“SDWA”), and analogous state laws. The SDWA’s Underground Injection Control Program establishes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. In response to concerns related to increased seismic activity in the vicinity of injection wells, regulators in some states are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission (“RRC”) adopted new oil and gas permit rules in October 2014 for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to conduct continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.  In addition, any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injury.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. For example, the EPA has taken the following actions and issued: guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel; final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of volatile organic compounds and methane emissions released during hydraulic fracturing; an advanced notice of proposed rulemaking in March 2014 under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing; and final rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management ("BLM") finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that "water cycle" activities associated with hydraulic fracturing may impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Louisiana and Texas, 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. Moreover, some states and local governments have enacted laws or regulations limiting hydraulic fracturing within their borders or prohibiting the activity altogether. In the event that 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.

18



Air Emissions
The Clean Air Act ("CAA") and comparable state laws, regulate emissions of various air pollutants from many sources in the United States, including crude oil and natural gas production activities through air emissions standards, construction and operating programs and the imposition of other compliance requirements. These laws and any implementing 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. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 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 October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, in June 2016, the EPA finalized rules under the CAA regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. Compliance with these requirements could increase our costs of development and production significantly.
Climate Change
The EPA has determined that greenhouse gases present an endangerment to public health and the environment and has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources of greenhouse gas emissions. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from a variety of sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions from completions and workovers from hydraulically fractured oil wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The BLM finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. However, both the U.S. House of Representatives and the Senate have introduced resolutions seeking to repeal the BLM methane rules under the Congressional Review Act and future implementation of the BLM methane rules is uncertain. However, the BLM and the EPA methane rules have substantial similarities with respect to pollution control equipment and leak detection and repair requirements. Compliance with rules to control methane emissions will likely require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and the increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states have established greenhouse gas cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases 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. 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, which could in turn have the effect of lowering the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases 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 greenhouse gases 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. Such climatic events could have an adverse effect on our financial condition and results of operations.
Endangered Species
The Federal Endangered Species Act, as amended (“ESA”), and analogous state laws restrict activities that could have an adverse effect on threatened or endangered species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our operations may be located in or near areas that are designated as habitat for

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endangered or threatened species. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, as a result of a court settlement the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2018 fiscal year. The presence of protected species or the designation of previously unidentified endangered or threatened species could impair our ability to timely complete well drilling and development and could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Employee Health and Safety
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, as amended, and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens.  
Other Laws and Regulations
State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and natural gas properties, establishment of maximum rates of production from oil and natural gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and natural gas could otherwise be produced from our properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field.
 

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Item 1A.
Risk Factors

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and natural gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “predicts,” “target,” “goal,” “plans,” “objective,” “potential,” “should,” or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; the Company undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risk and uncertainties:
the market prices of oil and natural gas;
volatility in the commodity-futures market;
financial market conditions and availability of capital;
future cash flows, credit availability and borrowings;  
sources of funding for exploration and development;
our financial condition;
our ability to repay our debt;
the securities, capital or credit markets;
planned capital expenditures;
future drilling activity;
uncertainties about the estimated quantities of our oil and natural gas reserves;
production;
hedging arrangements;
litigation matters;
pursuit of potential future acquisition opportunities;
general economic conditions, either nationally or in the jurisdictions in which we are doing business;
legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations;
the creditworthiness of our financial counterparties and operation partners; and
other factors discussed below and elsewhere in this Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

We recently emerged from bankruptcy, which could adversely affect our business and relationships.
 
It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 Cases could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:

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key suppliers could terminate their relationship or require financial assurances or enhanced performance;
the ability to renew existing contracts and compete for new business may be adversely affected;
the ability to attract, motivate and/or retain key executives and employees may be adversely affected;
employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and
competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
 
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of our Plan of Reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.
 
In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan of Reorganization, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in the Company’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

There is a limited trading market for our securities and the market price of our securities is subject to volatility.
 
Upon our emergence from bankruptcy, our old common stock was canceled and we issued new common stock. Our common stock is now listed on the over-the-counter market. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan of Reorganization, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A of this Annual Report on Form 10-K. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.
 
The Company intends to join a national securities exchange. However, no assurances can be given regarding the Company’s ability to do so in a timely manner or at all.
  
Upon our emergence from bankruptcy, the composition of our Board changed significantly.
 

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Pursuant to our Plan of Reorganization, the composition of the Board changed significantly. Upon emergence, the Board is now made up of seven directors, of which five have not previously served on the Board. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that the new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and plans of the Company may differ materially from those of the past.
 
The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.
 
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.
 
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
 
Funds associated with the Majority Second Lien Noteholders (as defined in the Plan of Reorganization) currently own a majority of our outstanding common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. Furthermore, pursuant to our Second Amended and Restated Certificate of Incorporation (the “Charter”), the Majority Second Lien Noteholders have the continuing right to nominate three members of the Board, subject to conditions on share ownership. In addition, our significant concentration of share ownership may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning stock in companies with significant stockholders.
 
We do not expect to pay dividends in the near future.
 
We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

Certain provisions of our Charter and our Bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
 
Certain provisions of our Charter and our Second Amended and Restated Bylaws (the “Bylaws”) may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws include, among other things, those that:
 
provide for a classified board of directors;
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and
limit the persons who may call special meetings of stockholders.

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.


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Oil prices and natural gas prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Oil and natural gas prices are volatile; a sustained decrease in the price of oil or natural gas would adversely impact our business.

Our success depends on the market prices of oil and natural gas. These market prices tend to fluctuate significantly in response to factors beyond our control. The prices we receive for our crude oil production are based on global market conditions. The general pace of global economic growth, the continued instability in the Middle East and other oil and natural gas producing regions and actions of the Organization of Petroleum Exporting Countries, as well as other economic, political, and environmental factors will continue to affect world supply and prices. Domestic natural gas prices fluctuate significantly in response to numerous factors including U.S. economic conditions, weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that limit future drilling activities for the industry.
 
Natural gas and crude oil prices are extremely volatile. High and low spot prices for New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude oil and NYMEX Henry Hub natural gas for were as follows:
 
 
2016
 
High
 
Low
West Texas Intermediate crude oil price range per barrel
$
54.06

 
$
26.21

Henry Hub natural gas price range per MMBtu
3.23

 
1.70

 
Average oil and natural gas prices varied substantially during the past few years. Any actual or anticipated reduction in natural gas and crude oil prices may further depress the level of exploration, drilling and production activity. We expect that commodity prices will continue to fluctuate significantly in the future.
 
Changes in commodity prices significantly affect our capital resources, liquidity and expected operating results. These lower prices, coupled with the slow recovery in financial markets that has significantly limited and increased the cost of capital, have compelled most oil and natural gas producers, including us, to reduce the level of exploration, drilling and production activity. This will have a significant effect on our capital resources, liquidity and expected operating results. Any sustained reductions in oil and natural gas prices will directly affect our revenues and can indirectly impact expected production by changing the amount of funds available to us to reinvest in exploration and development activities. Further reductions in oil and natural gas prices could also reduce the quantities of reserves that are commercially recoverable. Additionally, further or continued declines in prices could result in additional non-cash charges to earnings due to impairment write-downs. Any such write down could have a material adverse effect on our results of operations in the period taken.
Our future revenues are dependent on the ability to successfully complete drilling activity.
Drilling and exploration are the main methods we utilize to replace our reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

reductions in oil and natural gas prices;
inadequate capital resources;
limitations in the market for oil and natural gas;
lack of acceptable prospective acreage;
unexpected drilling conditions;
pressure or irregularities in formations;
equipment failures or accidents;
unavailability or high cost of drilling rigs, equipment or labor;

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title problems;
compliance with governmental regulations;
mechanical difficulties; and
risks associated with horizontal drilling.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain.
In addition, while lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically, higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increased costs for, such drilling equipment, services and personnel. Such shortages could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues.
 
A sustained depression of oil and natural gas prices can continue to affect our ability to obtain funding on acceptable terms. This may hinder or prevent us from meeting our future capital needs.
 
We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
 
Our new common stock is listed on the OTCQX marketplace and is held by a small group of investors.

The lack of market and float of our stock can have an adverse effect on the market liquidity of our common stock and, as a result, the market price for our common stock could become more volatile. If we are unable to become re-listed on a national securities exchange and increase the market value per share of our common stock, it may be difficult to attract the interest of analysts, institutional investors, investment funds and brokers.
 
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
 
We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities, including outstanding options, or otherwise will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.
Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve report. These differences may be material.
The proved oil and natural gas reserve information included in this report are estimates. These estimates are based on reports prepared by NSAI and RSC, our independent reserve engineers, and were calculated using the unweighted average of first-day-of-the-month oil and natural gas prices in 2016. The prices we receive for our production may be lower than those upon which our reserve estimates are based. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:


25



historical production from the area compared with production from other similar producing wells;
the assumed effects of regulations by governmental agencies;
assumptions concerning future oil and natural gas prices; and
assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

the quantities of oil and natural gas that are ultimately recovered;
the production and operating costs incurred;
the amount and timing of future development expenditures; and
future oil and natural gas sales prices.
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this document should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the standardized measure of discounted future net cash flows from proved reserves are generally based on 12-month average prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

the amount and timing of actual production;
supply and demand for oil and natural gas;
increases or decreases in consumption; and
changes in governmental regulations or taxation.
In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, and which we use in calculating our PV-10, is not necessarily 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.
Our operations are subject to governmental risks that may impact our operations.
Our operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting and changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies or price gathering-rate controls. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

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Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our oil and natural gas exploration and production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of permits, including drilling permits, before conducting regulated activities; plugging and abandonment and site reclamation requirements; the restriction of types, quantities and concentration of materials that can be released into the environment; limiting or prohibiting drilling activities on certain lands lying within wilderness, wetlands and other protected areas, the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition 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 as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination. Failure to comply with environmental laws and regulations may result in the assessment of civil and criminal fines and penalties, the revocation of permits or the issuance of injunctions restricting or prohibiting our operations in certain areas. Moreover, private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. Any changes in legal requirements  related to the protection of the environment could result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements. Such changes could also require us to make significant expenditures to attain and maintain compliance, and also have the potential to reduce demand for the oil and gas we produce and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as government reviews of such activity could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and 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. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. For example, the EPA has taken the following actions and issued: guidance under the SDWA for hydraulic fracturing activities involving the use of diesel fuel; final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of volatile organic compounds and methane emissions released during hydraulic fracturing; an advanced notice of proposed rulemaking in March 2014 under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing; and finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or

27



produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Louisiana and Texas, 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. There has also been increased public scrutiny of seismic events in areas where hydraulic fracturing of wastewater disposal activities occur. Moreover, some states and local governments have enacted laws or regulations limiting hydraulic fracturing within their borders or prohibiting the activity altogether. In the event that 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.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.
Certain scientific studies have found that emissions of carbon dioxide, methane and other “greenhouse gases” are contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA determined that greenhouse gases present an endangerment to public health and the environment and has issued regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from a variety of sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, including greenhouse gas emissions from completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The BLM finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. . However, both the U.S. House of Representatives and the Senate have introduced resolutions seeking to repeal the BLM methane rules under the Congressional Review Act and future implementation of the BLM methane rules is uncertain. However, the BLM and the EPA methane rules have substantial similarities with respect to pollution control equipment and LDAR requirements. Compliance with rules to control methane emissions will likely require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and the increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states have established greenhouse gas cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases 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. 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, which in turn could have the effect of lowering the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases 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 greenhouse gases 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. Such climatic events could have an adverse effect on our financial condition and results of operations.
We have incurred losses from operations and may continue to do so in the future.
The Predecessor Company incurred operating losses of $494.5 million and $354.8 million, for the years ended December 31, 2015 and 2014, respectively. Post emergence from bankruptcy in 2016, the Successor company had an operating

28



loss of $2.6 million. Our development 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.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate, and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) enacted in 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”) and the SEC 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 U.S. 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 the associated rules also require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.  If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures; therefore reducing our ability to execute hedges to reduce risk and protect cash flow.
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 regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, or 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. Increased volatility may make us less attractive to certain types of investors. Finally, 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 instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our 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 on us is uncertain.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. Such legislative changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or

29



all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.
Our use of oil and natural gas price hedging contracts may limit future revenues from price increases and result in significant fluctuations in our net income.
We have historically used hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. We had no hedge settlements in 2016 and did not have any hedge contracts at December 31, 2016.
We account for our oil and natural gas derivatives using fair value accounting standards. Each derivative is recorded on the balance sheet as an asset or liability at its fair value. Additionally, changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is executed. We have elected not to apply hedge accounting treatment to our swap and call derivative contracts and, as such, all changes in the fair value of these instruments are recognized in earnings. Our fixed price physical contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment.
In the future, we will continue to be exposed to volatility in earnings resulting from changes in the fair value of our derivative instruments. See Note 10-“Derivative Activities” in the Notes to Consolidated Financial Statements in “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
Oil and natural gas prices are volatile. All of our crude oil hedging contracts expired in 2015. If we choose not to or are unable to replace our hedges, our cash flows from operations will be subjected to increased volatility.
We have historically entered into hedging transactions for our oil and natural gas production revenues to reduce our exposure to fluctuations in the price of oil and natural gas. All of our crude oil hedging contracts expired in 2015. As a result, 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 or be unable to replace our hedges, which will subject our cash flows from operations to increased volatility.
Because our operations require significant capital expenditures, we may not have the funds available to replace reserves, maintain production or maintain interests in our properties.
We must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. Historically, we have paid for these expenditures with cash from operating activities, proceeds from debt and equity financings and asset sales. Our revenues or cash flows could be reduced because of lower oil and natural gas prices or for other reasons. If our revenues or cash flows decrease, we may not have the funds available to replace reserves or maintain production at current levels. If this occurs, our production will decline over time. Other sources of financing may not be available to us if our cash flows from operations are not sufficient to fund our capital expenditure requirements. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. Where we are not the majority owner or operator of an oil and natural gas property, we may have no control over the timing or amount of capital expenditures associated with the particular property. If we cannot fund such capital expenditures, our interests in some properties may be reduced or forfeited.

30



If we are unable to replace reserves, we may not be able to sustain production at present levels.
Our future success depends largely upon our ability to find, acquire or develop additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. At December 31, 2016, 85% of our total estimated proved reserves by volume were undeveloped. By their nature, estimates of proved undeveloped reserves and timing of their production are less certain particularly because we may chose not to develop such reserves on anticipated schedules in future adverse oil or natural gas price environments. Recovery of such reserves will require significant capital expenditures and successful drilling operations. The lack of availability of sufficient capital to fund such future operations could materially hinder or delay our replacement of produced reserves. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.
We may incur substantial impairment writedowns.
If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and natural gas prices decline, we may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial position. Furthermore, any sustained decline in oil and natural gas prices may require us to make further impairments. Prior to emerging from bankruptcy we accounted for our Oil and Gas properties using the Successful Efforts Method of Accounting. We reviewed our proved oil and natural gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis.
Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. For the years ended December 31, 2015, we recorded impairment related to oil and natural gas properties of $452.0 million. The decline in oil and natural gas prices precipitated the loss of estimated proved reserves for our oil and natural gas producing properties. Additionally, the prospect of lower future prices raised substantial doubt about our ability to continue as a going concern and consequently all estimated proved undeveloped reserves were excluded from our estimated total proved reserves as of December 31, 2015 and the carrying cost of the related undeveloped leasehold was impaired.
Upon emerging from bankruptcy we implemented Fresh Start Reporting and changed to the Full Cost Method of accounting for our Oil and Natural Gas Properties. The Full Cost Method requires a ceiling test be performed each quarter to determine impairment. The reserve value basis used in the Ceiling Test is the SEC calculated reserves. The SEC value of reserves utilizes a look back at the last twelve month commodity prices. The Ceiling Test performed on December 31, 2016 resulted in an impairment of $2.5 million.
A majority of our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Essentially all of our estimated proved reserves at December 31, 2016 were associated with our Louisiana, Texas and Mississippi properties which include the Haynesville Shale and TMS Trend. Accordingly, if the level of production from these properties substantially declines or is otherwise subject to a disruption in our operations resulting from operational problems, government intervention (including potential regulation or limitation of the use of high pressure fracture stimulation techniques in these formations) or natural disasters, it could have a material adverse effect on our overall production level and our revenue.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. For example, Chesapeake operates certain properties in the Haynesville Shale Trend. As of December 31, 2016, approximately 73% of our reserves and approximately 40% of our sales volumes were attributable to non-operated properties. We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with

31



respect to them versus those fields in which we are the operator. Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.
Our ability to sell natural gas and receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.
We operate primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend and (ii) Southwest Mississippi and Southeast Louisiana which includes the TMS Trend. A number of companies are currently operating in the Haynesville Shale Trend. If drilling in these areas continues to be successful, the amount of natural gas being produced could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in this region. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for Northwest Louisiana and East Texas may not occur or may be substantially delayed for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our natural gas to interstate pipelines. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas production at significantly lower prices than those quoted on NYMEX or that we currently project, which would adversely affect our results of operations.
A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, the interruption could temporarily adversely affect our cash flow.
We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them.
The acquisition of properties requires us to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well, facility or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion or subsurface groundwater contamination, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities relating to the acquired assets and indemnities are unlikely to cover liabilities relating to the time periods after closing. We may be required to assume any risk relating to the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. The incurrence of an unexpected liability could have a material adverse effect on our financial position and results of operations.
Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could materially adversely affect our financial condition, results of operations and cash flows.
Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from the largest of these sources as a percent of oil and natural gas revenues for the year ended December 31, 2016, and 2015 were 87%, and 74%, respectively. Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our financial condition, results of operations and cash flows. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.
Customer credit risks could result in losses.
Our exposure to non-payment or non-performance by our customers and counterparties presents a credit risk. Generally, non-payment or non-performance results from a customer’s or counterparty’s inability to satisfy obligations. We monitor the creditworthiness of our customers and counterparties and established credit limits according to our credit policies and guidelines, but cannot assure that any losses will be consistent with our expectations. Furthermore, the concentration of our customers in the energy industry may impact our overall exposure to credit risk as customers may be similarly affected by

32



prolonged changes in economic and industry conditions.  The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2016 and 2015 are as follows:
 
 
Year Ended December 31,
 
2016
 
2015
Genesis Crude Oil LP
44
%
 
26
%
Sunoco, Inc.
30
%
 
17
%
Occidental Energy MA
13
%
 
%
BP Energy Company
%
 
31
%
 
Competition in the oil and natural gas industry is intense, and we are smaller and have a more limited operating history than some of our competitors.
We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources than us. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for oil and natural gas properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Our success depends on our management team and other key personnel, the loss of any of whom could disrupt our business operations.
Our success will depend on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.
The oil and natural gas exploration and production business involves many uncertainties, economic risks and operating risks that can prevent us from realizing profits and can cause substantial losses.
The nature of the oil and natural gas exploration and production business involves certain operating hazards such as:
well blowouts;
cratering;
explosions;
uncontrollable flows of oil, natural gas, brine or well fluids;
fires;
formations with abnormal pressures;
shortages of, or delays in, obtaining water for hydraulic fracturing operations;
environmental hazards such as crude oil spills;
natural gas leaks;
pipeline and tank ruptures;
unauthorized discharges of brine, well stimulation and completion fluids or toxic gases into the environment;
encountering naturally occurring radioactive materials;
other pollution; and
other hazards and risks.

33



Any of these operating hazards could result in substantial losses to us. As a result, substantial liabilities to third parties or governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of our properties. Additionally, some of our oil and natural gas operations are located in areas that are subject to weather disturbances such as hurricanes. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production.
We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.
We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:
personal injury;
bodily injury;
third party property damage;
medical expenses;
legal defense costs;
pollution in some cases;
well blowouts in some cases; and  
workers compensation.
As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. A loss in connection with our oil and natural gas properties could have a materially adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.
We may be unable to maintain compliance with the financial maintenance or other covenants in the Exit Credit Facility, which could result in an event of default under the Exit Credit Facility that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.
Under the Exit Credit Facility, the Company and the Subsidiary are required to maintain certain financial covenants including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.5 to 1.0 initially, and increasing to 2.0 to 1.0 or after December 31, 2018, (ii) Secured Debt Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.10 to 1.00 initially, and increasing to 1.35 to 1.00 and 1.50 to 1.00 after March 31, 2017 and September 30, 2017, respectively, in the case of clauses (i) and (ii), to be determined as of January 1 and July 1 each year and as of the date of any Material Acquisition (as defined in the Exit Credit Agreement) or Material Disposition (as defined in the Exit Credit Agreement), (iii) commencing with the fiscal quarter ending March 31, 2018, a ratio of Debt (as defined in the Exit Credit Agreement) as of the end of each fiscal quarter to EBITDAX for the twelve months ending on the last day of such fiscal quarter, not to exceed 4.00 to 1.00, (iv) limitations on Consolidated Cash Balance (as defined in the Exit Credit Agreement), (v) limitations on general and administrative expenses and (vi) minimum liquidity requirements.
The Exit Credit Facility also contains certain covenants which, among other things, and subject to certain exceptions, restrict the Company’s and certain of its subsidiaries’ ability to incur additional debt or liens, pay dividends, repurchase equity interests, prepay other indebtedness, sell, transfer, lease or dispose of assets, and make investments in or merge with another company.
If the Company were to violate any of the covenants under the Exit Credit Facility and were unable to obtain a waiver, it would be considered a default after the expiration of any applicable grace period. If the Company were in default under the Exit Credit Facility, then the lenders thereunder may exercise remedies in accordance with the terms thereof, including declaring all outstanding borrowings immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due.

34



Restrictive covenants in our Exit Credit Facility may restrict our ability to pursue our business strategies.
The Exit Credit Facility limits our ability, among other things, to:
    incur additional indebtedness;
incur additional liens;
pay dividends or make other distributions;
    make investments;
    sell or discount of receivables;
    enter into mergers;
    sell properties;
    terminate swap agreements;
    enter into transactions with affiliates;
    maintain gas imbalances;
    enter into take-or-pay contracts or make other prepayments;
    enter into swap agreements; and
    make capital expenditures.
The Exit Credit Facility also requires us to comply with certain financial maintenance covenants as discussed above.
A breach of any of these restrictive covenants could result in a default under the in Exit Credit Facility. If a default occurs, the lenders may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. If we are unable to repay our indebtedness when due or declared due, the lenders thereunder will also have the right to proceed against the collateral pledged to them to secure the indebtedness.
The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.
As of the date of filing this Annual Report, we have outstanding (i) costless warrants granted to the New 2L Notes Purchasers representing 2.5 million shares of our common stock, (ii) out-of-the-money 1.3 million warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million and (iii) 1.9 million restricted stock awards. The exercise of equity awards, including any stock options that we may grant in the future, and warrants, and the sale of shares of our common stock underlying any such options or the warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares. Investors may experience dilution in the net tangible book value of their investment upon the exercise of the warrants and any stock options that may be granted or issued pursuant to the warrants in the future.



35



Item 1B.
Unresolved Staff Comments
None.


36



Item 3.
Legal Proceedings

A discussion of our current legal proceedings is set forth in Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements in “Item 8—Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
For a discussion of our Chapter 11 Cases, please see “Items 1. and 2. Business and Properties” under the headings “Voluntary Reorganization under Chapter 11 of the Bankruptcy Code,” “Commitment Letter” and “Plan of Reorganization” of this Annual Report on Form 10-K.


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Item 4.
Mine Safety Disclosures

Not Applicable.

 

38



PART II

Item 5.
 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Price of Our Common Stock
The Predecessor Company's common stock was traded on the New York Stock Exchange (“NYSE”) under the symbol “GDP” throughout 2015.  The New York Stock Exchange (the "NYSE") delisted our common stock due to our abnormally low trading price in January 2016. Our common stock subsequently traded on the OTC Pink marketplace under the symbol "GDPMQ" until its cancellation on October 12, 2016, pursuant to the bankruptcy court's confirmation of our Plan of Reorganization. Upon our bankruptcy emergence, we issued 6.8 million shares of our new common stock, and commenced trading on the OTCQX marketplace under the symbol "GDPP" on December 8, 2016.
At February 9, 2016, the number of holders of record of our common stock was 709 and 9,108,826 shares were outstanding. High and low sales prices for our common stock for each quarter during 2016 and 2015 were as follows:
 
 
2016
 
2015
 
High
 
Low
 
High
 
Low
First Quarter
$
0.28

 
$
0.05

 
$
4.76

 
$
2.35

Second Quarter
0.08

 
0.02

 
4.45

 
1.55

Third Quarter
0.05

 
0.01

 
1.86

 
0.54

Fourth Quarter (Successor Company December, 2016)
14.00

 
10.75

 
0.90

 
0.20


The over-the-counter market quotations for 2016 reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.
 
Dividends
We do not anticipate declaring any dividends on the Successor Company common stock in the foreseeable future.
Issuer Repurchases of Equity Securities
No private or open market repurchases of our common stock were made by or on our behalf or any that of any affiliated purchaser for the year ended December 31, 2016.
For information on securities authorized for issuance under our equity compensation plans, see “Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”
Unregistered Sales of Equity Securities
None that have not been previously reported by us on a Current Report on Form 8-K.

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Performance
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the company specifically incorporates it by reference into such filing.
The following graph compares the cumulative five-year total return to stockholders on our common stock relative to the cumulative total returns of the S&P 500 Index and the Russell 2000 Index. An investment of $100 is assumed to have been made in our common stock and the indexes on December 31, 2010 and its relative performance is tracked through December 31, 2016.

peercompanygrapha01.jpg



40



Item 6.
Selected Financial Data  
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.
 


41



Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations  

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Annual Report on Form 10-K in “Item 8—Financial Statements and Supplementary Data”, and the information set forth in “Item 1A—Risk Factors”.


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Overview
We are an independent oil and natural gas company engaged in the exploration, development and production of properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.
We seek to increase shareholder value by growing our oil and natural gas reserves, production, revenues and cash flow from operating activities (“operating cash flow”). In our opinion, on a long term basis, growth in oil and natural gas reserves, cash flow and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company.
Management strives to increase our oil and natural gas reserves, production and cash flow through exploration and development activities. We develop an annual capital expenditure budget, which is reviewed and approved by our board of directors on a quarterly basis and revised throughout the year as circumstances warrant. We take into consideration our projected operating cash flow and externally available sources of financing, such as bank debt, asset divestures, issuance of debt and equity securities and strategic joint-ventures, when establishing our capital expenditure budget.
We place primary emphasis on our operating cash flow in managing our business. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains (losses), non-cash general and administrative expenses and impairments.
Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. Such pricing factors are largely beyond our control; however, we employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.
Key Developments
The following general economic developments and corporate actions in 2015 and 2016 had and may continue to have a significant impact on our financial position and results of operations:
The Current, Sustained Low Commodity Price Environment
Beginning in the second half of 2014, commodity prices, particularly crude oil, began to decline sharply. The decline became precipitous late in the fourth quarter of 2014 and into 2015.  Crude oil prices declined from a high of over $105 per barrel in June 2014 to less than $27 per barrel in February 2016. Natural gas prices faced similar downward pressure during the same period, dropping below $1.70 per MMBtu in December 2015. As an exploration and production company with interests in unconventional oil and natural gas shale properties that require large investments of capital to develop, the significant magnitude of this price decline has had a particularly material and adverse impact on our results of operations and led to substantial changes in our operating and drilling programs.
In response to the decline in commodity prices, we focused on managing our balance sheet to reduce leverage and preserve liquidity during this extended low commodity price environment. Specifically, we took the following steps in 2016 and 2015 to mitigate the effects of lower crude oil prices on our operations and conserve capital:

Reduced our capital expenditures for 2016 to $6.3 million as compared to $85.5 million in 2015;
Generated savings by negotiating cost reductions from service providers in both 2015 and 2016;
Froze salaries at 2014 levels initially and subsequently materially reduced the salaries of our management team;
Reduced our staff headcount over 50% from year-end 2014 levels;
Reduced discretionary expenditures.
Despite having taken these measures, with the continued low commodity price environment, our cash flow from operations substantially declined and the stock price of our common stock declined significantly. On January 13, 2016, the NYSE formally commenced delisting procedures for our common stock due to our abnormally low trading price. On January 21, 2016, the NYSE filed a Form 25 with the SEC, notifying us of the removal of our common stock from listing.

43



In addition to the previously mentioned measures taken to reduce costs and increase liquidity, in January 2016, we launched a comprehensive plan (the “Recapitalization Plan”) to exchange our notes and preferred stock for common stock in an effort to reduce our dividend and debt service cost. The Recapitalization Plan was unsuccessful and the financial condition of the Company became unsustainable.
Chapter 11 Bankruptcy
On April 15, 2016 (the “Petition Date”), we and our subsidiary Goodrich Petroleum Company, L.L.C. filed voluntary Bankruptcy petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division, to pursue a Chapter 11 plan of reorganization. We filed a motion with the Bankruptcy Court seeking joint administration of the Chapter 11 Cases under the caption In re Goodrich Petroleum Corporation, et al. (Case No. 16-31975). The Chapter 11 Cases constituted an event of default that accelerated our obligations under all our outstanding debt instruments. The agreements governing our debt instruments at the time provided that as a result of the Bankruptcy Petitions, the principal and interest due thereunder was immediately due and payable. However, any efforts to enforce such payment obligations under the debt instruments were automatically stayed as a result of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments was subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. We subsequently operated the company as a debtor-in-possession.
We received Bankruptcy Court confirmation of our joint plan of reorganization on September 28, 2016 and subsequently emerged from bankruptcy on October 12, 2016. Although we are no longer a debtor-in-possession, we were a debtor-in-possession through October 12, 2016. As such, aspects of our bankruptcy proceedings and related matters are described below in order to provide context and explain a part of our financial condition and results of operations for the period presented. We are accounting for the bankruptcy in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, “Reorganizations”. We filed a series of first day motions with the Bankruptcy Court that allowed us to continue to conduct business without interruption. These motions are designed primarily to minimize the impact on our operations, customers and employees.
On April 18, 2016, the Bankruptcy Court issued certain additional interim and final orders with respect to our first-day motions and other operating motions that allowed us to operate their businesses in the ordinary course. Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the us or their property to recover, collect or secure a claim arising prior to the filing of the Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from us, or to create, perfect or enforce any lien against the our properties, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim were enjoined.
During the Chapter 11 Cases, we conducted normal business activities and were authorized to continue to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders, critical vendors and other third parties, such as royalty holders and partners.

On July 25, 2016 we entered into and filed a motion with the Bankruptcy Court to approve a commitment letter (the “Commitment Letter”) with a group of investors for the new issuance of 13.50% Convertible Senior Secured Second Lien Notes in the initial aggregate principal amount of $40.0 million (the “Convertible Second Lien Notes”). The Bankruptcy Court approved the motion on August 4, 2016 which allowed us to submit a revised plan of organization to the Bankruptcy Court.
Emergence from Bankruptcy
The Company's joint plan of reorganization (the “Plan of Reorganization”) was confirmed by the Bankruptcy Court on September 28, 2016 and we emerged from bankruptcy on October 12, 2016 (the "Effective Date").
On October 12, 2016, we entered into an Exit Credit Agreement (including all amendments, the “Exit Credit Facility”) by which various lenders have agreed to provide us with a $20.0 million senior secured term loan credit facility, with an outstanding principal amount of $20.0 million. The Commitment Letter provided for the issuance of $40.0 million in Convertible Second Lien Notes that mature on the later of August 30, 2019 or six months after the maturity of the Exit Credit Agreement. A total of $20.0 million in proceeds from the issuance of the Convertible Second Lien Notes were used to repay amounts outstanding under the existing Second Amended and Restated Credit Agreement (including

44



all amendments, the “Senior Credit Facility”) and $20.0 million in proceeds will be used to fund the Company’s Haynesville Shale Trend drilling program.
Plan of Reorganization
The significant features of the Plan of Reorganization confirmed by the Bankruptcy Court are as follows:

1.
Each holder of an allowed priority claim (other than a priority tax claim or administrative claim) received either: (a) cash equal to the full allowed amount of its claim or (b) such other treatment as may otherwise be agreed to by such holder, the Debtors, the holders of at least 50% in principal amount of the Second Lien Notes (the “Majority Consenting Noteholders”), and the purchasers of the new Convertible Second Lien Notes (“New 2L Notes Purchasers”);

2.
Each holder of a secured claim (other than a priority tax claim, Senior Credit Facility claim, or Second Lien Notes claim) received, at the Debtors’ election and with the consent of the Majority Consenting Noteholders, either: (a) cash equal to the full allowed amount of its claim, (b) reinstatement of such holder’s claim, (c) the return or abandonment of the collateral securing such claim to such holder, or (d) such other treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders, and the New 2L Notes Purchasers;

3.
The Senior Credit Facility claims were paid cash in an amount sufficient to reduce the Senior Credit Facility claims to a balance of $20.0 million while the remaining $20.0 million owed was refinanced into a new senior secured term loan credit facility;

4.
The Second Lien Notes claims were deemed allowed in the aggregate amount of $175.0 million of principal plus accrued and unpaid interest through the Petition Date. Except to the extent a holder of a Second Lien Note claim agreed in writing to less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Second Lien Notes claim, each holder of a Second Lien Notes claim received their pro rata share of 98% of the new equity interests in the reorganized company (the “New Equity Interests”), subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million;

5.
Holders of unsecured notes claims received, pro rata with holders of other general unsecured claims, their pro rata share of the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million; plus its pro rata share of 2% of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal of $230.0 million;

6.
Holders of allowed general unsecured claims had the option to elect on their ballot to (a) receive, pro rata with holders of unsecured notes claims, its pro rata share of the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million; plus its pro rata share of 2% of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to 10% of the New Equity Interests with a maturity of 10 years and an equity strike price equal to $230.0 million, or (b) treat its allowed general unsecured claim as a convenience class claim by releasing any claims in excess of $10,000;

7.
Holders of convenience class claims received either: (a) cash equal to the full allowed amount of such holder’s claim or (b) such lesser treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders and the New 2L Notes Purchasers;


45



8.
Equity interests in the Subsidiary were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Subsidiary did not receive any distribution or retain any property on account of such equity interest in the Subsidiary. Equity interests in the Company were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Company did not receive any distribution or retain any property on account of such equity interest in the Company.

Fresh Start and Full Cost Accounting

Upon our emergence from bankruptcy, we adopted Fresh Start Accounting in accordance with the requirements of FASB ASC 852, "Reorganizations". This resulted in our becoming a new entity for financial reporting purposes. At that time, our assets and liabilities were recorded at their fair values as of the Effective Date. The effects of the Plan of Reorganization and our application of fresh start accounting are reflected in our consolidated financial statements as of December 31, 2016. The related adjustments were recorded in our consolidated statement of operations as reorganization items for the year to date period ending October 12, 2016.

The application of fresh start accounting and the effects of the implementation of our Plan of Reorganization resulted in our Consolidated Financial Statements on or after October 12, 2016 not being comparable with the Consolidated Financial Statements prior to that date. Our financial results for future periods following our application of fresh start accounting will be different from historical trends and the differences may be material.

All references made to "Successor" or "Successor Company" relate to the Company on and subsequent to the Effective Date. References to the “Successor 2016 Period” relate to the period from October 13, 2016 to December 31, 2016. References to "Predecessor" or “Predecessor Company” refer to the Company prior to the Effective Date. References to the “Predecessor 2016 Period” relate to the period from January 1, 2016 to October 12, 2016. The consolidated financial statements of the Successor have been prepared with the assumption that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Additional information pertaining to our adoption, application, and effects of fresh start accounting is contained in Note 2 to these Consolidated Financial Statements.

On October 12, 2016, to better reflect the true economics of our exploration and development of oil and gas reserves, we transitioned from the Successful Efforts Method of Accounting for Oil and Gas Activities to the Full Cost Method.

Financial Statement Classification of Liabilities Subject to Compromise

The Predecessor financial statements included amounts classified as liabilities subject to compromise, the majority of which were equitized on October 12, 2016, upon our emergence from bankruptcy. See Note 3 to these Consolidated Financial Statements for additional information.
2016 Financial and Operating Results included:

We emerged from bankruptcy as a reorganized Company with $30 million in equity and $60 million in debt;
We ended the year with 303 Bcfe of proved oil and natural gas reserves;
We ended the year with $36.9 million in cash;
We restarted our drilling program by participating in two successful wells in the Haynesville Shale Trend;
We realized cash proceeds of $23.8 million from the issuance of 2.3 million share of common stock in a private placement.
Tuscaloosa Marine Shale Trend
 
We held approximately 215,000 gross (156,000 net) acres in the TMS as of December 31, 2016. During 2016, we did not conduct any drilling operations in the TMS; however, we had 2 gross (1.7 net) wells drilled in 2015 still waiting on completion. Our net production volumes from our TMS wells represented approximately 35% of our total equivalent production on a Mcfe basis and approximately 99% of our total oil production for the year ended December 31, 2016. During 2016, we spent $1.5 million in the TMS, which included $0.2 million for leasehold costs.

46



Haynesville Shale Trend
Our relatively low risk development acreage in this trend is primarily centered in and around Angelina and Nacogdoches counties, Texas and DeSoto and Caddo parishes, Louisiana. We hold approximately 48,000 gross (24,000 net) acres as of December 31, 2016 producing from or prospective for the Haynesville Shale. We drilled 2 gross (0.4 net) wells in 2016 spending $4.1 million of which $0.3 million was leasehold cost. Our net production volumes from our Haynesville Shale Trend wells represented approximately 62% of our total equivalent production on a Mcfe basis for 2016.

Eagle Ford Shale Trend
 
We sold our Eagle Ford Shale Trend proved reserves and a portion of the associated leasehold on September 4, 2015. We have retained as of December 31, 2016 approximately 14,000 net acres of undeveloped leasehold in Frio County, Texas, which is prospective for future development or sale.


47



Results of Operations
In addition to adopting Fresh Start Accounting , the Successor also adopted the Full Cost Method of Accounting as of October 12, 2016. Prior to October 12, 2016, the Predecessor used the Successful Efforts Method of Accounting. The results of operations of the Successor and the Predecessor are not generally comparable in 2016 nor are they individually comparable with prior periods. We believe however, that production volumes, oil and natural gas revenues, lease operating expenses and production and other taxes are generally comparable consequently, unless otherwise indicated the tables and discussions below include pro forma results of the Predecessor and the Successor together for the periods in 2016 for these operational items. We believe this pro forma presentation gives the reader a better understanding of our operational results in 2016.
The Predecessor 2016 Period results of operation reflects the period from January 1, 2016 to October 12, 2016. The Net income of $369.9 million was primarily the result of the $399.4 million gain on the implementation of the Plan of Reorganization. Under the Plan of Reorganization, we experienced gains from the cancellation of our then outstanding Second Lien Notes and unsecured senior notes with the related accrued interest offset by the expenses incurred in the reorganization and the fair value of the Successor Company equity received by the senior note holders pursuant to the Plan of Reorganization.
The Successor 2016 Period results of operations reflects the period from October 13, 2016 to December 31, 2016. The net loss of $4.3 is primarily the result of the $2.5 million impairment expense recorded on our oil and gas properties. The Successor adopted the Full Cost Method of Accounting which requires a quarterly Full Cost Ceiling Test. The fair value assigned to the Successor's oil and gas assets upon adoption of Fresh Start Accounting was based upon a market participant fair value while the Full Cost Ceiling Test is based upon the value of oil and gas properties using SEC reserve pricing. The SEC pricing reflects a look back of 12 months and as of December 31, 2016, oil and gas prices were lower than the prospective prices used by a market participant fair value resulting in a Full Cost Ceiling write down.
The following table reflects our summary operating information for the periods presented in thousands except for price and volume data. Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.
 
October 13, to December 31, 2016
January 1, 2016 to October 12, 2016
 
Year Ended December 31,
 
Successor
Predecessor
 
Pro forma
 
Predecessor
 
 
Summary Operating Information:
 
 
 
2016
 
2015
 
Variance
Revenues:
 
 
 
 

 
 

 
 

 
 

Natural gas
$
2,327

$
5,817

 
$
8,144

 
$
14,282

 
$
(6,138
)
 
(43
)%
Oil and condensate
4,210

15,210

 
19,420

 
64,795

 
(45,375
)
 
(70
)%
Natural gas, oil and condensate
6,537

21,027

 
27,564

 
79,077

 
(51,513
)
 
(65
)%
Net Production:
 
 
 
 

 
 

 
 

 
 

Natural gas (Mmcf)
1,198

4,357

 
5,555

 
7,984

 
(2,429
)
 
(30
)%
Oil and condensate (MBbls)
88

388

 
476

 
1,336

 
(860
)
 
(64
)%
Total (Mmcfe)
1,723

6,687

 
8,410

 
16,000

 
(7,590
)
 
(47
)%
Average daily production (Mcfe/d)
21,538

23,381

 
22,979

 
43,836

 
(20,857
)
 
(48
)%
Average Realized Sales Price Per Unit:
 
 
 
 

 
 

 
 

 
 

Natural gas (per Mcf)
$
1.94

$
1.34

 
$
1.47

 
$
1.79

 
$
(0.32
)
 
(18
)%
Oil and condensate (per Bbl)
$
47.84

$
39.20

 
$
40.80

 
$
48.50

 
$
(7.70
)
 
(16
)%
Oil and condensate (per Bbl) including the
   effect of realized gains/losses on
   derivatives
$
47.84

$
39.20

 
$
40.80

 
$
89.13

 
$
(48.33
)
 
(54
)%
Average realized price (per Mcfe)
$
3.79

$
3.14

 
$
3.28

 
$
4.94

 
$
(1.66
)
 
(34
)%
 

48



Oil and Natural Gas Revenue
Natural gas, oil and condensate revenues on a pro forma basis decreased in 2016 compared to 2015 reflecting a decrease in our average realized sales prices for natural gas, oil and condensate and a reduction in natural gas, oil and condensate production. The decreases in natural gas, oil and condensate realized sales prices compared to 2015 contributed approximately $12.8 million to the decrease in natural gas, oil and condensate revenue, and the decrease in natural gas, oil and condensate production contributed approximately $38.7 million to the decrease in natural gas, oil and condensate revenue. The sale of our Eagle Ford Shale Trend properties in September 2015 contributed $22.9 million to the decrease in revenues attributed to decreased in volumes.
The difference on a pro forma basis between our average realized prices inclusive of net cash derivative settlements in the years ended December 31, 2016 and 2015 relates to our oil contracts. We had no natural gas derivative contract settlements during 2016 or 2015.  We had no oil derivative settlements in 2016 while in 2015, we had oil derivative settlements on an average of 3,500 Bbls per day at an average fixed price of $96.11 per Bbl.
Operating Expenses

(in thousands)
October 13, to December 31, 2016
 
January 1, 2016 to October 12, 2016
 
Year Ended December 31,
 
Successor
 
Predecessor
 
Pro forma

 
Predecessor
 
 
 
 
 
 
 
 
2016
 
2015
 
Variance
Lease operating expenses
$
2,109

 
$
6,504

 
$
8,613

 
$
15,522

 
$
(6,909
)
(45
)%
Production and other taxes
619

 
1,946

 
2,565

 
4,639

 
(2,074
)
(45
)%
Transportation and processing
228

 
1,265

 
*
 
4,663

 

 %
Exploration

 
577

 
*
 
41,783

 

 %
 
 
 
 
 
Per Mcfe
October 13, to December 31, 2016
 
January 1, 2016 to October 12, 2016
 
Year Ended December 31,
 
Successor
 
Predecessor
 
Pro forma

 
Predecessor
 
 
 
 
 
 
 
 
2016
 
2015
 
Variance
Lease operating expenses
$
1.22

 
0.97

 
$
1.02

 
$
0.97

 
$
0.05

5
 %
Production and other taxes
$
0.36

 
$
0.29

 
$
0.30

 
$
0.29

 
$
0.01

3
 %
Transportation and processing
$
0.13

 
$
0.19

 
*
 
$
0.29

 

 %
Exploration

 
$
0.09

 
*
 
$
2.61

 

 %
 * Not comparable

Lease Operating Expense
Our lease operating expense (“LOE”) during 2016 on a pro forma basis decreased compared to 2015. The decrease was the result of a $4.8 million decrease from our Eagle Ford Shale Trend properties that were sold in September 2015 and lower operating costs for our TMS properties. Workover expense in 2016 for the Successor Company period was $0.4 million and for the Predecessor Company period was $0.8 million which added $0.23 and $0.12 per Mcfe respectively to unit expense compared to workover expense of $1.3 million in 2015 which added $0.08 per Mcfe to unit expense.
Production and Other Taxes
Production and other taxes for the year ended 2016 on a pro forma basis included production tax of $1.0 million and ad valorem tax of $1.6 million. Production and other taxes decreased in 2016 compared to 2015 mainly due to the sale of our Eagle Ford Shale Trend properties in September 2015. Lower production rates and lower commodity prices have been offset by a number of wells reaching their exemption maturity. The State of Mississippi has enacted an exemption from the existing 6.0% severance tax for horizontal wells drilled after July 1, 2013 with production commencing before July 1, 2018, which will be partially offset by a 1.3% local severance tax on such wells. The exemption is applicable until the earlier of (i) 30 months from

49



the date of first sale of production or (ii) until payout of the well cost is achieved. The State of Louisiana has also enacted an exemption from the existing 12.5% severance tax for horizontal wells with production commencing after July 31, 1994. The exemption is applicable until the earlier of (i) 24 months from the date of first sale of production or (ii) until payout of the well cost is achieved. The net revenues from our wells drilled in our TMS acreage in Southwestern Mississippi and Southeast Louisiana have been favorably impacted by these exemptions.
Transportation and Processing
Transportation and processing expense for the 2016 Successor period reflects the restructuring of the marketing of our outside operated natural gas volumes in an effort to reduce transportation and processing cost.
Transportation and processing expense for the 2016 Predecessor period was generally lower due to lower produced natural gas volumes. Our natural gas production incurs substantially all of our transportation and processing cost.
Transportation and processing expense for the Predecessor in 2015 included $2.7 million in cost related to the Eagle Ford Shale properties sold in September 2015 which did not impact 2016 results.

Exploration
The Successor Company adopted the Full Cost Method of accounting as of October 12, 2016 resulting in Exploration Cost being capitalized to the full cost pool rather than expensed.
The Exploration expense in the Predecessor 2016 period was lower as result of the Leasehold impairments taken in in 2015.
The Exploration expense in the 2015 Predecessor period included leasehold impairments taken as result of our deemed financial inability to develop or extend the leases.

(in thousands)
October 13, to December 31, 2016
 
January 1, 2016 to October 12, 2016
 
For the Year Ended December 31, 2015
 
Successor
 
Predecessor
 
Predecessor

 
Depreciation, depletion & amortization
$
1,556

 
$
8,276

 
$
79,339

 
Impairment
2,486

 
1,583

 
452,037

 
General & administrative
2,200

 
14,474

 
27,702

 
Gain on sale of assets
(2
)
 
(840
)
 
(53,451
)
 
 
 
Per Mcfe
October 13, to December 31, 2016
 
January 1, 2016 to October 12, 2016
 
For the Year Ended December 31, 2015
 
Successor
 
Predecessor
 
Predecessor

 
Depreciation, depletion & amortization
$
0.90

 
$
1.24

 
$
4.96

 
Impairment
$
1.44

 
0.24

 
$
28.25

 
General & administrative
1.28

 
2.16

 
$
1.73

 
Gain on sale of assets

 
(0.13
)
 
$
(3.34
)
 
Depreciation, Depletion & Amortization (“DD&A”)
DD&A expense in the 2016 Successor period were calculated on the Full Cost Method of Accounting adopted upon our emergence from bankruptcy based upon asset values as of October 12, 2016 established by Fresh Start Accounting.
DD&A expense in the 2016 Predecessor Period reflects reduced rates due to the impairment taken in 2015, in addition to lower production.


50



DD&A expense in the 2015 Predecessor period reflects higher DD&A rates calculated before having taken $452 million impairment at the end of 2015 as discussed below. Additionally, the 2015 expense reflected the DD&A on the Eagle Ford Shale properties that were sold in September 2015.
Impairment
The Successor Company recorded a $2.5 million impairment on oil and gas properties as a result of the Full Cost Ceiling Test performed on December 31, 2016.
The Predecessor Company recorded a $1.6 million impairment on the value of materials inventory during the Predecessor 2016 Period.
We recorded a $452.0 million impairment in 2015, comprised of $135.6 million for our Haynesville Shale Trend properties, $310.2 million for our TMS properties and $7.0 million for other properties. The decline in oil and natural gas prices precipitated the loss of estimated proved reserves for our oil and natural gas producing properties. Additionally, the prospect of lower future prices had raised substantial doubt about our ability to continue as a going concern. Consequently all estimated proved undeveloped reserves had been excluded from our estimated total proved reserves as of December 31, 2015 and the carrying cost of the related undeveloped leasehold was impaired.  
General and Administrative Expense (“G&A”)
The Successor Company recorded $2.2 million in G&A expense in 2016 which includes $0.2 million of share based compensation. As a result of adopting the Full Cost Method of Accounting, $0.5 million of G&A cost directly attributed to our capital development program was capitalized to the the full cost pool.
The Predecessor Company recorded $14.5 million in G&A expense in 2016 which includes $3.3 million in share based compensation. During the Predecessor 2016 period, we reduced our staff headcount by more than 30% from year-end 2015 levels. The higher rate per Mcfe for 2016 compared to 2015 reflects a 47% reduction in oil and natural gas production which increased per unit expenses.
The Predecessor Company recorded $27.7 million in G&A expenses which includes $6.7 million in share based compensation.
 Gain on Sale of Assets
In 2015 the Predecessor recognized a $53.5 million gain on sale of assets.  The 2015 gain is almost entirely associated with the sale of our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale Trend located in La Salle and Frio counties in south Texas. In 2016, the Predecessor recognized $0.8 million gain on the settlement of the Eagle Ford Shale property escrow account.
No gain or loss was recognized for properties sold during the Successor period.
Other Income (Expense)
 
 
 
 
 
 
 
October 13, to December 31, 2016
 
January 1, 2016 to October 12, 2016
 
Year Ended December 31, 2015
(In thousands)
Successor
 
Predecessor
 
Predecessor
Other Income (Expense):
 

 
 

 
 
Interest expense
$
(1,824
)
 
$
(11,398
)
 
$
(54,807
)
Interest income and other
1

 
117

 

Gain (loss) on derivatives not designated as hedges

 
30

 
7,367

Gain on extinguishment of debt

 

 
62,555

Restructuring

 
(5,128
)
 

Average funded borrowings adjusted for debt discount
26,399

 
*

 
579,393

Average funded borrowings
59,503

 
*

 
579,722

* - Not Meaningful

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Interest Expense
 
Interest expense in the 2016 Predecessor period reflects interest only through April 15, 2016. which was our Bankruptcy Petition Date. We ceased accruing interest on the Second Lien Notes and unsecured senior notes on the Petition Date.

Interest expense in the Successor period reflects the interest incurred on the Exit Credit Facility and the Paid-in-Kind interest on the 13.50% Convertible Second Lien Notes due 2019.

Interest expense for the Predecessor year ended December 31, 2015 reflects interest on average outstanding borrowing of $579.7 million for the entire year.

Gain on Derivatives Not Designated as Hedges
 
The gain on derivatives was less than $0.03 million in 2016 Predecessor Period. We had no derivatives in the 2016 Successor period.
Gain on derivatives was $7.4 million for 2015.  The gain includes net cash receipts of $54.3 million off set by the decrease in the fair value of $46.9 million. There were no natural gas derivative contract settlements during 2015.  The decrease in the fair value consists of a $0.5 million gain on our natural gas derivatives and a $47.4 million loss on our oil derivatives. The decrease in fair value of our oil derivatives reflects settled contracts and the ultimate expiration of all of our oil derivative contracts in December 2015.  The gain on our the natural gas derivative contracts is reflective of the portion of such contracts that expired during 2016 and the decline in natural gas futures prices in the latter half of 2015.

Restructuring

As a result of the efforts to restructure the Company outside of bankruptcy during the first quarter of 2016 and the subsequent preparation involved in filing the Chapter 11 Cases, we incurred significant professional fees and other costs. Restructuring costs during the first and second quarters of 2016 totaled $4.3 million and $0.8 million, respectively.

Reorganization items, net

The Predecessor Company realized a gain on reorganization in 2016 of $399.4 million as a result of implementing the Plan of Reorganization and adopting Fresh Start Accounting on October 12, 2016. The gain on the settlement of liabilities subject to compromise was $395.9 million and the gain on fresh start adjustments of $19.5 million was reduced by a net $16.0 million related to professional fees and adjustments to debt. Reorganization costs incurred for professional fees as of October 12, 2016 was $11.0 million. In addition to the costs of professional fees, reorganization cost was affected by various non-cash adjustments to the carrying amounts of our Second Lien Notes and senior notes, including a $5.5 million charge for the unwinding of an embedded derivative related to the Second Lien Notes. See Note 3- "Fresh Start Accounting" in the Notes to Consolidated Financial Statements in Item 8- "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K.

Gain(loss) on Extinguishment of Debt
 
On October 1, 2015 the Predecessor exchanged $158.2 million of 2020 Notes for $75.0 million of new 8.875% Second Lien Notes. The transaction was accounted for as a troubled debt restructure and recognized a gain on extinguishment of debt of $62.6 million.
 
Income Tax Benefit
 
We recorded no income tax benefit for the years 2016 and 2015. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred asset as of December 31, 2016.

We elected to early adopt the provisions of ASU 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” in 2016 on a retrospective basis. The amendments in this update seek to simplify the presentation of deferred income taxes and require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The implementation did not have a material impact on the Company’s consolidated statement of operations, balance

52



sheet or statement of cash flows. As the noncurrent deferred tax amounts net to zero, they are no longer presented on the Consolidated Balance Sheets.

 Adjusted EBITDA/EBITDAX  
 
Adjusted EBITDA/EBITDAX is a supplemental non-US 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. EBITDA reflects the absence of exploration expense in the Full Cost Method of Accounting. We define Adjusted EBITDAX as earnings before interest expense, income tax, DD&A, exploration expense, share based compensation and impairment of oil and natural gas properties. In calculating Adjusted EBITDA/EBITDAX, gains/losses on derivatives, less net cash received or paid in settlement of commodity derivatives, gain on reorganization and gain on extinguishment of debt are excluded from Adjusted EBITDA/EBITDAX. Other excluded items include Interest income and other, Gain/loss on sale of assets, Gain/loss on early extinguishment of debt and Other expense. Adjusted EBITDA/EBITDAX is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDA/EBITDAX should not be considered an alternative to net income (loss), as defined by US GAAP. The following table presents a reconciliation of the non-US GAAP measure of Adjusted EBITDA/EBITDAX to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP.
 
 
October 13, to December 31, 2016
 
January 1, 2016 to October 12, 2016
 
Year Ended December 31, 2015
 
Successor
 
Predecessor
 
Predecessor
(In thousands)
 
 
 
 
 
Net gain (loss) (US GAAP)
$
(4,307
)
 
$
369,944

 
$
(479,424
)
Depreciation, depletion and amortization
1,556

 
8,276

 
79,339

Exploration Expense

 
577

 
41,783

Impairment
2,486

 
1,583

 
452,037

(Gain) loss on extinguishment of debt

 

 
(62,555
)
Stock based compensation
240

 
3,307

 
6,689

Interest expense
1,824

 
11,398

 
54,807

Gain on reorganization
(130
)
 
(399,422
)
 

(Gain) on derivatives not designated as hedges

 
(30
)
 
(7,367
)
Net cash received (paid) in settlement of derivative instruments

 

 
54,274

Other items (1)
(3
)
 
(957
)
 
(52,327
)
Adjusted EBITDA/EBITDAX
$
1,666

 
$
(5,324
)
 
$
87,256

 
(1)
Other items include interest income and other, gain/loss on sale of assets, income taxes and other expense.

Management believes that this non-US GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry. Our computations of Adjusted EBITDA/EBITDAX may not be comparable to other similarly totaled measures of other companies.


53



LIQUIDITY AND CAPITAL RESOURCES
 
Overview
 
Predecessor Company (January 1, 2016 to October 12, 2016)

Our primary sources of cash were cash on hand, cash from operating activities, cash proceeds from borrowings under our Senior Credit Facility and cash proceeds from the settlement of the escrow account associated with the our Eagle Ford Shale Trend producing properties sold in 2015. We used cash in 2016 to fund our capital spending, pay interest on amounts outstanding on the Senior Credit Facility and pay expenses associated with the bankruptcy.

On April 15, 2016 we filed a voluntary petition seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, to pursue a Chapter 11 plan of reorganization. Our bankruptcy and subsequent emergence therefrom had a significant impact on our financial condition and operating results, including the extinguishment of approximately $426.2 in indebtedness related to the cancellation of our unsecured senior notes and other unsecured claims. We also incurred one-time costs that are associated with our reorganization, primarily professional fees, that affected our results of operations.

On August 4, 2016, the Bankruptcy Court approved a commitment letter (the “Commitment Letter”) between the Company and a group of investors for the issuance of 13.50% Convertible Senior Secured Second Lien Notes in the initial aggregate principal amount of $40.0 million (the “Convertible Second Lien Notes”).
 
On October 12, 2016, we entered into an Exit Credit Agreement by which various lenders agreed to provide us with a $20.0 million senior secured term loan credit facility, with an outstanding principal amount of $20.0 million. The Commitment Letter provided for the issuance of $40.0 million in Convertible Second Lien Notes that mature on the later of August 30, 2019 or six months after the maturity of the Exit Credit Agreement. A total of $20.0 million in proceeds from the issuance of the Convertible Second Lien Notes were used to repay amounts outstanding under the existing Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”) and $20.0 million in proceeds was and will be used to fund the Company’s Haynesville Shale Trend drilling program.
Successor Company (October 13, 2016 to December 31, 2016)
Our primary sources of cash on and after our emergence from bankruptcy on October 12, 2016 were cash on hand, cash flow from operating activities, proceeds from the sale of the Convertible Second Lien Notes, proceeds from the private placement of our common stock and proceeds from the sale of non-core oil and gas properties. We used cash to fund our capital expenditures, to pay interest on and pay down amounts outstanding on the Exit Credit Facility and to pay professional fees related to the reorganization.
Capital Resources
We have emerged from bankruptcy a much stronger company. We have $36.9 million cash on hand as of December 31, 2016. We believe that the cash on hand and the cash flows we are generating are sufficient to meet our investing, financing and working capital requirements in 2017. We believe the results of the capital investments we are making in 2017 will generate additional cash flows and additional value which will allow us to raise capital to continue our capital development into 2018 and beyond.
The table below summarizes our cash flows for the periods indicated (in thousands):
 
 
October 13, to December 31, 2016
 
January 1, 2016 to October 12, 2016
 
 
For Year Ended December 31, 2015
 
Cash flow statement information:
Successor
 
Predecessor
 
 
Predecessor
 
Net Cash:
 

 
 

 
 
 

 
Used in operating activities
$
(4,327
)
 
$
(16,684
)
 
 
$
(17,011
)
 
Used in investing activities
(2,383
)
 
(3,495
)
 
 
(4,874
)
 
Provided by financing activities
39,880

 
12,077

 
 
33,659

 
Increase (decrease) in cash and cash equivalents
$
33,170

 
$
(8,102
)
 
 
$
11,774

 
 At December 31, 2016, we had positive working capital of $28.6 million and $47.2 in long-term debt.

54



Cash Flows
 
For the Period October 13, 2016 to December 31, 2016
 
Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers of our cash flow from operations. Changes in working capital also impact cash flows. Net cash used in operating activities for the 2016 Successor period totaled $4.3 million impacted by the payment of $6.7 million of professional fees incurred and accrued in the prior period.
 
Investing activities: Net cash used in investing activities was $2.4 million for the 2016 Successor period. While we booked capital expenditures of approximately $4.3 million, we paid out cash amounts totaling $3.2 million in the period. The difference is attributed to utilizing $0.4 million of net cash calls and a net $0.5 million increased in the capital expenditure accrual. The Successor period also reflects the receipt of $0.8 million in proceeds from the December 2016 sale of the shallow rights in our Longwood properties located in Louisiana. We conducted drilling and completion operations on two gross wells in in the Successor period.
 
Financing activities: Net cash provided in financing activities for Successor period consisted of net proceeds from the issuance of 13.5% Second Lien Notes of $40.0 million and net proceeds from the sale of common stock of $23.6 million partially offset by net repayments of borrowings under the our Senior Credit and Exit Credit Facilities of $23.7 million.
Debt consisted of the following balances as of the dates indicated (in thousands):
 
 
Successor
 
Predecessor
 
December 31, 2016
 
December 31, 2015
 
Principal
 
Carrying
Amount
 
Fair
Value
 
Principal
 
Carrying
Amount (5)
 
Fair
Value (1)
Exit Credit Facility (7)
$
16,651

 
$
16,651

 
16,651

 
$

 
$

 
$

13.50% Convertible Second Lien Notes (8)
41,170

 
30,554

 
29,036

 

 

 

Senior Credit Facility

 

 

 
27,000

 
25,387

 
27,000

8.0% Second Lien Senior Secured Notes due 2018 (2) (6)

 

 

 
100,000

 
87,529

 
14,512

8.875% Second Lien Senior Secured Notes due 2018 (6)

 

 

 
75,000

 
91,364

 
7,586

8.875% Senior Notes due 2019 (6)

 

 

 
116,828

 
115,599

 
9,346

3.25% Convertible Senior Notes due 2026 (6)

 

 

 
429

 
429

 
64

5.0% Convertible Senior Notes due 2029 (3) (6)

 

 

 
6,692

 
6,692

 
67

5.0% Convertible Senior Notes due 2032 (4) (6)

 

 

 
98,664

 
95,882

 
6,923

5.0% Convertible Exchange Senior Notes due 2032 (6)

 

 

 
26,849

 
42,625

 
26,649

Total debt
$
57,821

 
$
47,205

 
$
45,687

 
$
451,462

 
$
465,507

 
$
92,147

 
 
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