SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 000-29187-87

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Texas		76-0415919
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)
1000 Louisiana Street, Suite 1500, Houston, TX		77002
(Address of principal executive offices)		(Zip Code)

(713) 328-1000
(Registrant’s telephone number)

     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 þ     NO o

     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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES þ     NO o

     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 (Check one):

Large accelerated filer þ     Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES o     NO þ

     The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of November 2, 2009, the latest practicable date, was 31,072,006.

 

 

EXPLANATORY NOTE

     We hereby amend and restate in its entirety Item 4 of Part I, “Controls and Procedures,” and Item 1A of Part II, “Risk Factors,” of our Form 10-Q for the quarter ended September 30, 2009, as originally filed with the Securities and Exchange Commission on November 9, 2009, to correctly describe the status of our remediation efforts regarding the material weakness in our internal control over financial reporting that was disclosed in our Form 10-K/A for the year ended December 31, 2008, our Form 10-Q/A for the quarter ended March 31, 2009 and our Form 10-Q for the quarter ended June 30, 2009. No other sections are affected.

CARRIZO OIL & GAS, INC.

FORM 10-Q/A
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
INDEX

		PAGE
PART I. FINANCIAL INFORMATION
Item 4. Controls and Procedures			2
PART II. OTHER INFORMATION
Item 1A. Risk Factors			3
Item 6. Exhibits			10
SIGNATURES			11

PART I

ITEM 4 - CONTROLS AND PROCEDURES

     Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. As described in more detail in our Form 10-K/A filed on August 17, 2009, we identified a material weakness in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) in connection with further review of our ceiling test impairments as of December 31, 2008 and March 31, 2009. As a result of this material weakness, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2009, our disclosure controls and procedures were not effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. We have outlined a number of initiatives, as discussed below, designed to remediate the material weakness.

     Changes in Internal Controls. As described in more detail in our Annual Report on Form 10-K/A for the year ended December 31, 2008, our Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2009 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, we identified a material weakness in our internal control over financial reporting and described a number of planned procedures designed to remediate this weakness, including (1) delegating preparation of certain critical workpapers to our financial reporting staff allowing our financial reporting manager to perform more qualitative review analysis, (2) removing the computational deficiencies from our standard ceiling test workpaper format, (3) improving workpaper formats and implement comparative analysis within these critical workpapers to enhance qualitative analysis, and (4) preparing a reconciliation of the quarter-to-quarter changes in costs associated with unevaluated property and proved undeveloped locations that will be used to determine the reclassification of costs to the full cost pool. These planned procedures were implemented in the quarter ended September 30, 2009 and our internal control over financial reporting, as modified by these procedures, were applied to the analysis of the ceiling test computation at September 30, 2009. However, management has not completed the testing of the effectiveness of these newly implemented procedures and, therefore, as stated above, has determined that our disclosure controls and procedures were not effective at September 30, 2009.

     This Item 4 should be read in conjunction with Part II, Item 9A in our Annual Report on Form 10-K/A for the year ended December 31, 2008, Part I, Item 4 in our Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2009 and Part I, Item 4 in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009.

PART II. OTHER INFORMATION

Item 1A		- Risk Factors

     In addition to the risk factors set forth below and the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K/A for the year ended December 31, 2008, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

     The global financial and credit crisis may have impacts on our liquidity and financial condition that we currently cannot predict.

     The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not continue to improve from their lows in early 2009. Our ability to access the capital markets or borrow money may be restricted or made more expensive at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions could have an impact on our natural gas and oil derivatives transactions if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to further reductions in the demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

     Natural gas and oil prices are highly volatile and have declined significantly since mid-2008, and lower prices will negatively affect our financial condition, planned capital expenditures and results of operations.

     Since July 2008, publicly quoted spot natural gas and oil prices have declined significantly from the record levels reached at that time. In the past, some oil and gas companies have reduced or curtailed production to mitigate the impact of low natural gas and oil prices. We have made similar decisions on selected properties during the last year and may decide to curtail additional production as a result of a decrease in prices in the future. The decrease in natural gas prices has had a significant impact on our financial condition, planned capital expenditures and results of operations. Further volatility in natural gas and oil prices or a prolonged period of low natural gas and oil prices may materially adversely affect our financial condition, liquidity (including our borrowing capacity under our senior credit facility), ability to finance planned capital expenditures and results of operations.

     Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil prices have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors beyond our control. These factors include:

     · the level of consumer product demand;

     · overall economic conditions;

     · weather conditions;

     · domestic and foreign governmental relations, regulations and taxes;

     · the price and availability of alternative fuels;

     · political conditions;

     · the level and price of foreign imports of oil and liquefied natural gas; and

     · the ability of the members of the Organization of Petroleum Exporting Countries to agree upon and maintain production constraints and oil price controls.

     As a result of an ongoing SEC staff review, we may be required to reclassify or write-off reserves.

     We own interests in approximately 2,630 gross acres in the Camp Hill Field in Anderson County, Texas, for which we reported approximately 8.2 MMBbls of proved reserves, including 5.0 MMBbls of proved undeveloped reserves (which represents approximately 6% of our total proved reserves) as of December 31, 2008. In connection with an ongoing review by the SEC’s staff of our Annual Report on Form 10-K for the year ended December 31, 2008, the staff has raised various issues regarding the classification of some of these reserves as proved. In late 2008, the SEC adopted new rules regarding the classification of reserves that will become effective with our reserve report as of year-end of 2009, which, among other things, generally require proved undeveloped reserves to be developed within five years, unless specific circumstances justify a longer time.

     As a result of various factors, including these new rules and our discussions with the SEC’s staff regarding their applicability to the Camp Hill Field, we may be required under applicable SEC rules to reclassify as unproved substantially all of our proved undeveloped reserves in the Camp Hill Field at year-end 2009 because these reserves will not be developed within the next five years. We may also be required under applicable SEC rules to write-off or reclassify to proved undeveloped, a portion of our proved developed reserves. The removal or reclassification of these reserves may be effective as of December 31, 2009, but could also involve removal of reserves in prior periods. A downward revision to our proved reserves in prior periods would likely result in amendments to our previously filed reports with the SEC to reflect a restatement of our financial statements, including a non-cash reduction in our historic net income. As an illustration, if we had removed all 8.2 MMBbls of our proved reserves in the Camp Hill Field, including both proved developed and proved undeveloped reserves, effective as of December 31, 2008, it would have resulted in a restatement of our financial statements to reflect an additional pre-tax non-cash ceiling test impairment of approximately $70.8 million.

     As of September 30, 2009, using the unweighted arithmetic average of the first day of the month price for each month from January through November 2009 (similar to the pricing methodology that will be required under the new SEC rules discussed below), the PV-10 value of the proved reserves in Camp Hill was approximately $150.9 million (including a PV-10 value of approximately $58.7 million attributable to the proved undeveloped reserves). PV-10 is the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

     We have actively engaged with and responded to the SEC throughout this review process. The staff continues to request, and we continue to provide, information regarding our reserves, including our proved developed nonproducing reserves and the economics of our proved reserves in the Camp Hill Field. However, we cannot predict the timing or final result of the staff’s review, and there can be no assurance that our determination following such review will not result in material changes to the classification of our reserves in the Camp Hill Field, and other adverse effects on our historic financial results.

     Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.

     There are uncertainties inherent in estimating natural gas and oil reserves and their estimated value, including many factors beyond the control of the producer. The reserve data included in our filings with the SEC represent only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results.

     Accordingly, reserve estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Additionally, there recently has been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves. In late 2008, the SEC adopted new rules regarding the classification of reserves. However, the interpretation of these rules and their applicability in different situations remains unclear in many respects. Changing interpretations of the classification standards or disagreements with our interpretations could cause us to write-down reserves. Please read “- As a result of an ongoing SEC staff review, we may be required to reclassify or write-off reserves.” In addition, the new SEC rules regarding classification of reserves

require that in calculating economic producibility of proved reserves, a company must generally use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Natural gas prices on the first day of each month in 2009 have been historically low and, as a result, when the applying the new rules, we may be required to reclassify certain proved reserves as of year-end 2009.

     As of December 31, 2008, approximately 58.6% of our proved reserves were proved undeveloped and proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2008 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

     The discounted future net cash flows included our filings with the SEC are not necessarily the same as the current market value of our estimated natural gas and oil reserves. As required by the SEC, the estimated discounted future net cash flows from proved reserves are currently based on prices and costs as of the date of the estimate and soon will be based on monthly averages. Actual future net cash flows also will be affected by factors such as:

     · the actual prices we receive for natural gas and oil;

     · our actual operating costs in producing natural gas and oil;

     · the amount and timing of actual production;

     · supply and demand for natural gas and oil;

     · increases or decreases in consumption of natural gas and oil; and

     · changes in governmental regulations or taxation.

     In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

     We participate in oil and natural gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.

     We frequently own less than 100% of the working interest in the oil and natural gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of the other working interest owners such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. In addition, the current economic downturn, the credit crisis and the volatility in natural gas and oil prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Many of our project partners are experiencing liquidity and cash flow problems. These problems may lead our partners to attempt to delay the pace of drilling or project development in order to preserve cash. A partner may be unable or unwilling to pay its share of project costs. In some cases,, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial condition.

     Our senior credit facility contains operating restrictions and financial covenants, and we may have difficulty obtaining additional credit.

     Over the past few years, increases in commodity prices and our successful drilling program led to increased proved reserve amounts, and the resulting increase in our estimated discounted future net revenue allowed us to increase the borrowing base under

our senior credit facility. However, as a result of the significant decline in natural gas and oil prices, or other factors, the lenders under our senior credit facility may adjust our borrowing base downward, thereby reducing our borrowing capacity. Our senior credit facility is secured by a pledge of substantially all of our producing natural gas and oil properties and assets, guaranteed by our subsidiaries CCBM, Inc., CLLR, Inc., Hondo Pipeline, Inc., Carrizo (Marcellus) LLC, Carrizo Marcellus Holding Inc. and Chama Pipeline Holding LLC and contains covenants that limit additional borrowings, dividends, the incurrence of liens, investments, sales or pledges of assets, changes in control, repurchases or redemptions for cash of our common stock, speculative commodity transactions and other matters. The senior credit facility also requires that specified financial ratios be maintained. Although we currently believe that we can meet all of our financial covenants with the business plan that we have put in place, our business plan is based on a number of assumptions, the most important of which is a relatively stable natural gas price at economically sustainable levels. If the price that we receive for our natural gas production deteriorates significantly from current levels, it could lead to lower revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants contained in our senior credit facility, including the covenants related to working capital, the ratio of EBITDA to debt coverage and the ratio of senior debt to EBITDA. In order to provide a further margin of comfort with regards to these financial covenants, we may seek to further reduce our capital and exploration budget, sell additional non-strategic assets or opportunistically modify or increase our natural gas hedges. There can be no assurance that we will be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our senior credit facility if a precipitous decline in natural gas prices were to occur in the future. We may not be able to refinance our debt or obtain additional financing, particularly in view of the restrictions of our senior credit facility on our ability to incur additional debt and the fact that substantially all of our assets are currently pledged to secure obligations under the senior credit facility. The restrictions of our senior credit facility and our difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results including:

     · our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes may be impaired;

     · the covenants in our senior credit facility that limit our ability to borrow additional funds and dispose of assets may affect our flexibility in planning for, and reacting to, changes in business conditions;

     · because our indebtedness is subject to variable interest rates, we are vulnerable to increases in interest rates;

     · any additional financing we obtain may be on unfavorable terms;

     · we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;

     · a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing portions of our drilling program, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing; and

     · we may become more vulnerable to downturns in our business or the economy.

     In addition, under the terms of our senior credit facility, our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing natural gas and oil prices. The next redetermination of our borrowing base is currently scheduled to occur in November 2009. Although we do not know at this time whether the borrowing base will be adjusted upwards or downwards, a negative adjustment could occur if the estimate of future prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination which occurred earlier this year. In the event the amount outstanding under our senior credit facility exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell a portion of our assets.

     We have limited experience drilling wells in the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our operations. We may face difficulties in securing and operating under authorizations and permits to drill and/or operate our Marcellus Shale wells.

     We have limited exploration experience and no development experience in the Marcellus Shale. As of October 21, 2009, we have participated or are participating in the drilling of only seven wells in the Marcellus Shale area. Other operators in the Marcellus Shale area also have limited experience drilling in the area. As a result, we have less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in other areas in which we operate. Moreover, the recent growth in exploration in the Marcellus Shale has drawn intense scrutiny from environmental interest groups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to our operations that may make it difficult or impossible to obtain permits and other needed authorizations to operate or otherwise make operating more costly or difficult than operating elsewhere.

     If we are unable to acquire adequate supplies of water for our Marcellus Shale drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

     We use a substantial amount of water in our Marcellus Shale drilling operations. Our inability to locate sufficient amounts of water, or dispose of water after drilling, could adversely impact our Marcellus Shale operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Furthermore, new environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.

     We cannot control the activities on properties we do not operate.

     We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues or could create liability for us for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards. With respect to properties that we do not operate:

     · the operator could refuse to initiate exploration or development projects;

     · if we proceed with any of those projects the operator has refused to initiate, we may not receive any funding from the operator with respect to that project;

     · the operator may initiate exploration or development projects on a different schedule than we would prefer;

     · the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects or participate in a substantial amount of the revenues from those projects; and

     · the operator may not have sufficient expertise or resources.

     Any of these events could significantly and adversely affect our anticipated exploration and development activities.

     If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints.

     Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering

systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

     Historically, we have generally delivered natural gas through gas gathering systems and gas pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Due to the lack of available pipeline capacity in the Barnett Shale, we have recently begun entering into firm transportation agreements in the Barnett Shale, which are more costly to us than the interruptible or short-term transportation agreements.

     If production in the Marcellus Shale by oil and has companies continues to expand, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. 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 the Marcellus Shale may not occur for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

     A portion of our natural gas and oil 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, it could temporarily adversely affect our cash flow.

     We may record ceiling limitation write-downs that would reduce our shareholders’ equity.

     We use the full-cost method of accounting for investments in natural gas and oil properties. Accordingly, we capitalize all the direct costs of acquiring, exploring for and developing natural gas and oil properties. Under the full-cost accounting rules, the net capitalized cost of natural gas and oil properties may not exceed a “ceiling limit” that is based on the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or the fair market value of unproved properties. If net capitalized costs of natural gas and oil properties exceed the ceiling limit, we must charge the amount of the excess to operations through depreciation, depletion and amortization expense. This charge is called a “ceiling limitation write-down.” This charge does not impact cash flow from operating activities but does reduce our shareholders’ equity. The risk that we will be required to write down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues, as further discussed under “Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.” Once incurred, a write-down of natural gas and oil properties is not reversible at a later date. We recorded non-cash ceiling test limitation write-downs at the end of 2008 and the end of the first quarter of 2009. We could incur additional write-downs in the future, particularly as a result of a decline of natural gas and oil prices or as a write-off of reserves.

     There is recently proposed legislation that could adversely affect our business.

     Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in fracturing process could adversely affect drinking water supplies. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase the Company’s costs of compliance and doing business. In addition, various states are also studying or considering various regulatory measures relating to hydraulic fracturing, including a moratorium on drilling in the Marcellus Shale that has been instituted in New York until the completion of a study by state officials regarding the potential environmental impact of Marcellus Shale development. We make

extensive use of hydraulic fracturing in our shale play operations and any federal, state or local increased regulation could increase our costs, limit our ability to conduct operations or otherwise adversely affect our business.

     In addition to various other federal, regional, state and local greenhouse gas legislation and regulations that are currently in effect or under development, the United States Congress is currently considering legislation that would significantly curtail national greenhouse gas emissions. The United States Environmental Protection Agency has also taken steps to declare that certain greenhouse gas emissions are contributing to air pollution which is an endangerment to human health, and may regulate greenhouse gas emissions under the federal Clean Air Act. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating costs and could have an adverse affect on the price or demand of the oil and gas we produce.

     President Obama’s Proposed 2010 Fiscal Year Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

     Enactment of a Pennsylvania severance tax on natural gas could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

     As a result of a funding gap in the state budget, the governor of the Commonwealth of Pennsylvania has proposed to its legislature the adoption of a severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is 5% of the value of the natural gas at wellhead, plus 4.7 cents per 1,000 cubic feet of natural gas severed. A substantial portion of our Marcellus Shale acreage is located in the Commonwealth of Pennsylvania. If Pennsylvania adopts such a severance tax, it could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

     As of December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, we had a material weakness in our internal control over financial reporting, and our internal control over financial reporting was not effective as of those dates. If we fail to maintain an effective system of internal controls, we may not be able to provide timely and accurate financial statements.

     As more fully described under “Controls and Procedures” in our Annual Report on Form 10-K/A for the year ended December 31, 2008, our Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2009, our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, and our Quarterly Report on Form 10-Q/A for the quarter ended September 30, 2009, our management identified a material weakness related to the ceiling test impairment and the classification of proved costs. As a result of the material weakness, management concluded that, as of December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, we did not maintain effective internal control over financial reporting.

     Management identified the material weakness referred to above in August of 2009 in a subsequent review of the December 31, 2008 and March 31, 2009 ceiling test calculations.

     The Public Company Accounting Oversight Board has defined a material weakness as a control deficiency, or combination of control deficiencies, that results in a reasonable possibility that a material misstatement of the annual or interim statements will not be prevented or detected on a timely basis. Accordingly, a material weakness increases the risk that the financial information we report contains material errors.

     We implemented initiatives to remediate the material weakness in our internal controls. The steps we have taken to address the material weakness may not be effective. However, any failure to effectively address a material weakness or other control deficiency or implement required new or improved controls, or difficulties encountered in their implementation, could limit our ability to obtain financing, harm our reputation, disrupt our ability to process key components of our result of operations and financial condition timely and accurately and cause us to fail to meet our reporting obligations under rules of the SEC and NASDAQ and our various debt arrangements.

Item 6		- Exhibits

     Exhibits required by Item 601 of Regulation S-K are as follows:

Exhibit
Number						Description
	31.1			—		CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2			—		CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Exhibit Index

Exhibit
Number						Description
	31.1			—		CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2			—		CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.