Rex Energy 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2009

OR

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

For the transition period from              to             .

Commission file number: 001-33610

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	20-8814402
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)

476 Rolling Ridge Drive, Suite 300

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). Check One:

Large Accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	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  ¨    No  x

36,837,312 common shares were outstanding on July 31, 2009.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD June 30, 2009

INDEX

			PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements.	4
		Consolidated Balance Sheets As of June 30, 2009 (Unaudited) and December 31, 2008	4
		Consolidated Statements of Operations (Unaudited) For the three and six month periods ended June 30, 2009 and June 30, 2008	5
		Consolidated Statement of Changes in Owners’ Equity (Unaudited) For the six month period ended June 30, 2009	6
		Consolidated Statements of Cash Flows (Unaudited) For the six month periods ended June 30, 2009 and June 30, 2008	7
		Notes to Consolidated Financial Statements (Unaudited)	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	28
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk.	35
	Item 4.	Controls and Procedures.	36
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings.	37
	Item 1A.	Risk Factors	37
	Item 4.	Submission of Matters to a Vote of Security Holders	37
	Item 6.	Exhibits	38
SIGNATURES			39
EXHIBIT INDEX			40

2

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q may contain forward-looking statements within the meaning of sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report, including but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks and uncertainties. Factors which may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by us in those statements include, among others, the following:

• adverse economic conditions in the United States and globally;

• the difficult and adverse conditions in the domestic and global capital and credit markets;

• domestic and global demand for oil and natural gas;

• sustained or further declines in the prices we receive for our oil and natural gas adversely affecting our operating results and cash flow;

• the effects of government regulation, permitting and other legal requirements;

• the quality of our properties with regard to, among other things, the existence of reserves in economic quantities;

• uncertainties about the estimates of our oil and natural gas reserves;

• our ability to increase our production and oil and natural gas income through exploration and development;

• our ability to successfully apply horizontal drilling techniques and tertiary recovery methods;

• the number of well locations to be drilled, the cost to drill and the time frame within which they will be drilled;

• drilling and operating risks;

• the availability of equipment, such as drilling rigs and transportation pipelines;

• changes in our drilling plans and related budgets;

• the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity; and

• other factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008 filed with the U.S. Securities and Exchange Commission.

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on such statements, which speak only as of the date of this report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Item 1. Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except per Share Amounts)

	June 30, 2009 (unaudited)			December 31, 2008
ASSETS
Current Assets
Cash and Cash Equivalents	$	2,414		$	7,046
Accounts Receivable		6,786			5,840
Related Party Receivable		506			—
Short-Term Derivative Instruments		2,666			8,153
Current Deferred Tax Asset		948			—
Inventory, Prepaid Expenses and Other		798			3,068
Total Current Assets		14,118			24,107
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		196,977			185,108
Unevaluated Oil and Gas Properties		77,076			65,564
Other Property and Equipment		19,912			19,388
Wells and Facilities in Progress		31,225			29,629
Pipelines		5,155			3,457
Total Property and Equipment		330,345			303,146
Less: Accumulated Depreciation, Depletion and Amortization		(64,859	)		(53,288	)
Net Property and Equipment		265,486			249,858
Assets Held for Sale		—			18,852
Intangible Assets and Other Assets – Net		1,480			1,628
Investment in RW Gathering		506			—
Long-Term Derivative Instruments		2,706			7,561
Total Assets	$	284,296		$	302,006
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	5,552		$	7,180
Accrued Expenses		4,751			7,388
Short-Term Derivative Instruments		3,116			—
Current Deferred Tax Liability		—			2,785
Total Current Liabilities		13,419			17,353
Senior Secured Line of Credit and Long-Term Debt		15,000			15,000
Long-Term Derivative Instruments		2,783			1,476
Long-Term Deferred Tax Liability		8,971			11,995
Other Deposits and Liabilities		5,767			7,322
Liabilities Related to Assets Held for Sale		—			1,838
Future Abandonment Cost		15,941			15,174
Total Liabilities	$	61,881		$	70,158
Commitments and Contingencies (See Note 11)
Owners’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 36,844,312 shares issued and outstanding on June 30, 2009 and 36,569,712 shares issued and outstanding on December 31, 2008.		37			37
Additional Paid-In Capital		292,161			291,133
Accumulated Deficit		(69,783	)		(59,322	)
Total Owners’ Equity		222,415			231,848
Total Liabilities and Owners’ Equity	$	284,296		$	302,006

See accompanying notes to the consolidated financial statements

4

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, $ and Shares in Thousands, Except per Share Data)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2009			2008			2009			2008
OPERATING REVENUE
Oil and Natural Gas Sales	$	11,516		$	25,874		$	20,314		$	45,490
Other Revenue		25			31			57			63
TOTAL OPERATING REVENUE		11,541			25,905			20,371			45,553
OPERATING EXPENSES
Production and Lease Operating Expenses		5,236			6,632			10,390			12,778
General and Administrative Expense		4,392			3,917			8,143			7,124
(Gain) Loss on Disposal of Assets		(28	)		194			400			151
Exploration Expense of Oil and Gas Properties		(247	)		982			835			1,281
Depreciation, Depletion, Amortization and Accretion		6,581			4,879			12,752			9,651
TOTAL OPERATING EXPENSES		15,934			16,604			32,520			30,985
INCOME (LOSS) FROM OPERATIONS		(4,393	)		9,301			(12,149	)		14,568
OTHER INCOME (EXPENSE)
Interest Income		1			176			2			183
Interest Expense		(379	)		(299	)		(774	)		(735	)
Loss on Derivatives, Net		(10,520	)		(73,640	)		(4,876	)		(89,920	)
Other Income (Expense)		13			14			(32	)		19
TOTAL OTHER INCOME (EXPENSE)		(10,885	)		(73,749	)		(5,680	)		(90,453	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(15,278	)		(64,448	)		(17,829	)		(75,885	)
Income Tax Benefit		5,841			26,061			7,045			30,687
LOSS FROM CONTINUING OPERATIONS		(9,437	)		(38,387	)		(10,784	)		(45,198	)
Income From Discontinued Operations, Net of Income Taxes		—			426			323			64
NET LOSS	$	(9,437	)	$	(37,961	)	$	(10,461	)	$	(45,134	)
Earnings per common share:
Basic – loss from continuing operations	$	(0.26	)	$	(1.12	)	$	(0.29	)	$	(1.39	)
Basic – income from discontinued operations		—			0.01			0.01			—
Basic – net loss	$	(0.26	)	$	(1.11	)	$	(0.28	)	$	(1.39	)
Basic – Weighted average shares of common stock outstanding		36,846			34,349			36,789			32,572
Diluted – loss from continuing operations	$	(0.26	)	$	(1.12	)	$	(0.29	)	$	(1.39	)
Diluted – income from discontinued operations		—			0.01			0.01			—
Diluted – net loss	$	(0.26	)	$	(1.11	)	$	(0.28	)	$	(1.39	)
Diluted – Weighted average shares of common stock outstanding		36,846			34,349			36,789			32,572

See accompanying notes to the consolidated financial statements

5

REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN OWNERS’ EQUITY

FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2009

(Unaudited, $ in Thousands)

	Common Stock			Additional Paid-In Capital		Accumulated Deficit			Total Owners’ Equity
	Shares	Par Value
BALANCE December 31, 2008	36,589,712	$	37	$	291,133	$	(59,322	)	$	231,848
Non-cash compensation expense	—		—		1,028		—			1,028
Issuance of Restricted Stock, Net	254,600		—		—		—			—
NET LOSS from continuing operations	—		—		—		(10,784	)		(10,784	)
NET GAIN from discontinued operations	—		—		—		323			323
BALANCE June 30, 2009	36,844,312	$	37	$	292,161	$	(69,783	)	$	222,415

See accompanying notes to the consolidated financial statements

6

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(10,461	)	$	(45,134	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Non-cash Expenses		1,168			1,117
Depreciation, Depletion, Amortization, Accretion and Impairment		12,753			11,071
Unrealized Gain Loss on Derivatives		14,207			78,856
Deferred Income Tax Benefit		(6,757	)		(30,643	)
Exploration Expense		47			1,102
Loss on Sale of Oil and Gas Properties		400			192
Changes in operating assets and liabilities, net of effects from acquisitions
Accounts Receivable		(682	)		(3,593	)
Inventory, Prepaid Expenses and Other Assets		608			(66	)
Accounts Payable and Accrued Expenses		(6,361	)		4,151
Net Changes in Other Assets and Liabilities		1,469			(237	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		6,391			16,816
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture		3,120			—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		17,362			305
Acquisitions of Undeveloped Acreage		(12,135	)		(30,051	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(19,370	)		(34,705	)
NET CASH USED IN INVESTING ACTIVITIES		(11,023	)		(64,451	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debts and Lines of Credit		(15,000	)		(41,296	)
Proceeds from Long-Term Debts and Lines of Credit		15,000			14,000
Proceeds from Lease Incentives		—			636
Proceeds from Secondary Offering		—			113,537
Offering Costs		—			(486	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		—			86,391
NET (DECREASE) INCREASE IN CASH		(4,632	)		38,756
CASH – BEGINNING		7,046			1,085
CASH – ENDING	$	2,414		$	39,841
SUPPLEMENTAL DISCLOSURES
Interest Paid		664			850
NON-CASH ACTIVITIES
Acquisitions of Undeveloped Acreage		—			12,701

See accompanying notes to the consolidated financial statements

7

REX ENERGY CORPORATION AND PREDECESSOR COMPANIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation (the “Company”) is an independent oil and gas company operating in the Illinois Basin and the Appalachian Basin of the United States. We have pursued a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations and our higher potential exploration drilling prospects and have actively sought to acquire complementary oil and natural gas properties.

Our consolidated financial statements include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and subsidiaries together.

The interim consolidated financial statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil and natural gas, future commodity prices for financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of oil and natural gas recovery techniques.

Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited consolidated and combined financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008.

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated.

Certain prior year amounts have been reclassified to conform to the report classifications for the three and six month periods ended June 30, 2009, with no effect on previously reported net income, retained earnings or stockholders’ equity. Approximately $11.0 million of valuation allowance related to the impairment of our evaluated oil and gas assets at December 31, 2008 was reclassified from Evaluated Oil and Gas Properties on the balance sheet to Accumulated Depreciation, Depletion and Amortization. Losses of approximately $7.8 million and $11.1 million for the three and six month periods ending June 30, 2008, respectively, have been reclassified from Realized Loss on Derivatives on the Statement of Operations to Loss on Derivatives, Net.

We adhere to Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS 19”) (Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932) for recognizing impairment of capitalized costs related to unproved properties. These costs are capitalized and periodically evaluated as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We consider time, geographic, geologic and engineering factors to evaluate the need for impairment of these costs. During the second quarter of 2009, we identified certain geographic regions, predominantly in areas prospective for the Marcellus Shale, that were outside of the scope of our current plans, increasing the probability of future lease expiration. As such, we recorded amortization expense on unproved properties of $419,000 as compared to $0 during the second quarter of 2008. These expenses are recorded as Depreciation, Depletion, Amortization and Accretion. As economic and strategic conditions change and we continue to develop unproved properties, our estimates will likely change and we may increase or decrease our amortization expense.

On May 5, 2008, we completed a public offering of 9,775,000 shares of common stock at an offering price of $20.75 per share. These shares included 5,775,000 shares offered by us (which includes 1,275,000 shares sold pursuant to the exercise of an over-allotment option granted to the underwriters’ of the offering) and 4,000,000 shares sold by certain selling stockholders. The net proceeds to us from the underwritten public offering, after underwriting discounts and offering expenses of approximately $6.8 million, were approximately $113.0 million.

On March 24, 2009, we completed the sale of certain of our oil and gas leases, wells and related assets predominantly located in the Permian Basin in the states of Texas and New Mexico. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (“SFAS 144”) (FASB ASC 360) we have reflected the results of operations of the above divestiture as discontinued operations, rather than a component of continuing operations. See Note 12 for additional information regarding discontinued operations.

8

We entered a Participation and Exploration Agreement on June 18, 2009, effective as of May 5, 2009, with Williams Production Company, LLC and Williams Production Appalachia, LLC (together “Williams”). Under the terms and conditions of the agreement, Williams may acquire, through a “drill-to-earn” structure, 50% of our working interest in certain oil and gas leases covering approximately 43,672 net acres in Centre, Clearfield and Westmoreland Counties, Pennsylvania. See Note 2 for additional information regarding the agreement with Williams.

2. ACQUISITIONS AND DISPOSITIONS

Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statements of operations from the closing date of acquisition. Purchase prices are allocated to the acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. Acquisitions are funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.

In the first quarter of 2009, we completed the sale of certain of our oil and gas leases, wells and related assets located primarily in the Permian Basin in the states of Texas and New Mexico for net proceeds of approximately $17.3 million and recorded a loss of $0.4 million. We have reflected the results of these divested operations as discontinued operations rather than a component of continuing operations. See Note 12 for additional information.

In the second quarter of 2009, we completed the acquisition of a 50% interest from our joint venture partner in certain oil and gas leases covering lands in Butler County, Pennsylvania for approximately $4.2 million. This acquisition gives us a 100% interest in these areas and increases our acreage holdings by approximately 6,500 net acres in this project region. In the transaction, we acquired only undeveloped acreage and we did not assume any liabilities.

In the second quarter of 2009, we entered into a Participation and Exploration Agreement (the “PEA”) with Williams that was effective as of May 5, 2009. Under the terms and conditions of the PEA, Williams may acquire, through a “drill-to-earn” structure, 50% of our working interest in certain oil and gas leases covering approximately 43,672 net acres in Centre, Clearfield and Westmoreland Counties, Pennsylvania (the “Project Area”). The PEA effectively provides that, for Williams to earn its 50% interest in the Project Area, Williams will bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled in the Project Area until such time as Williams has invested approximately $74.0 million (approximately $33.0 million on behalf of us and $41.0 million for Williams’ 50% share of the wells). In addition, Williams committed to participate in drilling a minimum of 10 horizontal wells in the Project Area to a depth sufficient to test the Marcellus Shale formation. Subject to certain termination rights, Williams agreed to fund its carry obligation prior to December 31, 2011 or make a cash payment to us for the remaining carry amount that has not been incurred at that time. Once Williams has completed its carry obligation and acquired 50% of our working interest in the leases within the Project Area, the parties will share all costs of the joint venture operations within an area of mutual interest (including the Project Area) in accordance with their participating interests, which are expected to be on a 50/50 basis. We believe this agreement will allow us to accelerate our activities in the Marcellus Shale while conserving capital at the same time.

In accordance with the terms of the PEA, Williams reimbursed us for approximately $3.1 million for Williams’ share of certain expenses incurred in the acquisition and development of oil and gas leases within the Project Area that we had previously paid. The PEA provides that we will continue to serve as operator of the Project Area until December 31, 2009, and thereafter, Williams will become the operator of the Project Area.

3. FUTURE ABANDONMENT COST

We account for future abandonment costs using SFAS No. 143,“Asset Retirement Obligations” (“SFAS 143”) (FASB ASC 410). This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed.

According to SFAS 143, if the estimate of fair value of a recorded asset retirement obligation changes, a revision is to be recorded to both the asset retirement obligation and the asset retirement cost. During the fourth quarter of 2008, we recognized an increase of $9.2 million in the estimated present value of the asset retirement obligations. The primary factors underlying the 2008 fair value revisions were an overall increase in abandonment cost estimates, the effect of changes in inflation and discount rates used in calculations and changes to the estimated useful life assumptions.

9

	June 30, 2009			June 30, 2008
	($ in Thousands)			($ in Thousands)
Beginning Balance	$	16,283		$	6,396
Asset Retirement Obligation Incurred		183			77
Asset Retirement Obligation Settled		(216	)		(106	)
Asset Retirement Obligation Cancelled on Sold Well Properties		(1,094	)		—
Asset Retirement Obligation Accretion Expense		785			353
Total Asset Retirement Obligation	$	15,941		$	6,720

4. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In December 2008, the SEC adopted rule changes to modernize its oil and gas reporting disclosures. The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago.

New disclosure requirements include: permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; enabling companies to also disclose their probable and possible reserves to investors (currently, the rules limit disclosure to only proved reserves); allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves; requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period, rather than the year-end price, to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. We expect the new guidance to change our disclosures, DD&A calculations and other fair value measurements. We are currently evaluating the impact for our annual report for the year ending December 31, 2009 and related financial statements.

In January 2009, the FASB issued FASB Staff Position (“FSP”) EITF 99-20-1, Amendments to the Impairment Guidance of EITF Issue No. 99-20 (“FSP EITF 99-20-1”) (FASB ASC 325). FSP EITF 99-20-1 amends the impairment guidance set for the in EITF Issue No. 99-20, Recognition of Interest Income and Impairment on Purchased Beneficial Interests and Beneficial Interests That Continue to Be Held by a Transferor in Securitized Financial Assets (“EITF 99-20”). This FSP also retains and emphasizes the objective of an other-than-temporary impairment assessment and the related disclosure requirements in FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, and other related guidance. FSP EITF 99-20-1 is effective for interim and annual reporting periods ending after December 15, 2008, and shall be applied prospectively. Retrospective application to a prior interim or annual reporting period is not permitted. We adopted FSP EITF 99-20-1 as of March 31, 2009. Adoption had no material effect on our financial position and results of operations.

On January 1, 2009, we adopted the provisions of SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (“SFAS 161”) (FASB ASC 815). SFAS 161 requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. Entities are required to provide enhanced disclosures about: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. See Note 7, Fair Value of Financial Instruments and Derivative Instruments for our disclosures required under SFAS 161.

Effective January 1, 2009, we adopted SFAS No. 141R, Business Combinations (“SFAS 141R”) (FASB ASC 805). SFAS 141R, which establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R also provides guidance for recognizing changes in an acquirer’s existing tax valuation allowances and tax uncertainty accruals that result from a business combination transaction as adjustments to income tax expense. We believe SFAS 141R may have a material impact on future consolidated financial statements, depending on the size and nature of any future business combinations that we may enter into, any future adjustments made to tax valuation allowances and uncertainty accruals related to business combinations entered into prior to January 1, 2009. During the six months ended June 30, 2009, the adoption did not have an impact on adjustments made to tax valuation allowances and uncertainty accruals related to business combinations entered into prior to January 1, 2009.

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Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements (“SFAS 157”) (FASB ASC 820) with respect to our financial assets and liabilities. In February 2008, the FASB issued FSP No. FAS 157-2, Effective Date of FASB Statement No. 157, (FASB ASC 820) which provided a one year deferral of the effective date of SFAS 157 for non-financial assets and non-financial liabilities, except those that are recognized or disclosed in the financial statements at fair value at least annually. Therefore, we adopted the provisions of SFAS 157 for non-financial assets and non-financial liabilities effective January 1, 2009. However, adoption of SFAS 157 for non-financial assets and non-financial liabilities did not have a material impact on our consolidated results of operations or financial condition.

In April 2009, the FASB issued Staff Position (“FSP”) No. 141R-1, Accounting for Assets and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP SFAS 141R-1”) (FASB ASC 805). FSP SFAS 141R-1 amends and clarifies SFAS 141R to address application issues regarding initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. FSP FAS 141R-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Although we did not enter into any significant business combinations during the first six months of 2009, we believe FSP SFAS 141R-1 may have a material impact on our future financial statements depending on the size and nature of any future business combinations that we may enter into.

In April 2009, the FASB issued FSP SFAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”) (FASB ASC 820). FSP SFAS 157-4 amends SFAS 157 and provides additional guidance for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly for fair value measurements. This FSP is applied prospectively with retrospective application not permitted. This FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity early adopting this FSP must also early adopt FSP SFAS 115-2 and SFAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (“FSP SFAS 115-2 and FAS 124-2”). Additionally, if an entity elects to early adopt either FSP SFAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP SFAS 107-1 and APB 28-1”) or FSP SFAS 115-2 and SFAS 124-2, it must also elect to early adopt this FSP. Adoption of FSP FAS 157-4 did not have a material impact on our financial position or results of operations.

In April 2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2 (FASB ASC 320). This FSP amends SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, SFAS 124, Accounting for Certain Investments Held by Not-for-Profit Organizations, and EITF Issue No. 99-20, Recognition of Interest Income and Impairment on Purchased Beneficial Interests and Beneficial Interests That Continue to Be Held by a Transferor in Securitized Financial Assets, to make the other-than-temporary impairments guidance more operational and to improve the presentation of other-than-temporary impairments in the financial statements. This FSP will replace the existing requirement that the entity’s management assert it has both the intent and ability to hold an impaired debt security until recovery. This FSP requires that our management assert it does not have the intent to sell the security and it is more likely than not it will not have to sell the security before recovery of its cost basis. This FSP also provides increased disclosure about the credit and noncredit components of impaired debt securities that are not expected to be sold. Additionally, this FSP requires increased and more frequent disclosures regarding expected cash flows, credit losses and an aging of securities with unrealized losses. Although this FSP does not result in a change in the carrying amount of debt securities, it does require that the portion of an other-than-temporary impairment not related to a credit loss for a held-to-maturity security be recognized in a new category of other comprehensive income and be amortized over the remaining life of the debt security as an increase in the carrying value of the security. This FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity may early adopt this FSP only if it also elects to early adopt FSP FAS 157-4. Also, if an entity elects to early adopt either FSP FAS 157-4 or FSP FAS 107-1 and APB 28-1, the entity is also required to early adopt this FSP. Adoption of FSP SFAS 115-2 and SFAS 124-2 did not have a material impact on our financial position or results of operations.

In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1 (FASB ASC 825). This FSP amends SFAS No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments not measured on the balance sheet at fair value in interim financial statements, as well as, in annual financial statements. Prior to this FSP, fair values for these assets and liabilities were only disclosed annually. This FSP applies to all financial instruments within the scope of SFAS 107 and requires all entities to disclose the method(s) and significant assumption(s) used to estimate the fair value of financial instruments. This FSP is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity may early adopt this FSP only if it also elects to early adopt FSP SFAS 157-4, FSP FAS 115-2 and FAS 124-2. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. Adoption of FSP SFAS 107-1 and APB 28-1 did not have a material impact on our financial position or results of operations.

In May 2009, the FASB issued SFAS No. 165,Subsequent Events, (“SFAS 165”) (FASB ASC 855) which establishes general standards for and disclosure of events that occur after the balance sheet date but before financial statements are issued. SFAS 165

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identifies the period after the balance sheet date that management should evaluate transactions that may occur for potential recognition or disclosure. This statement also provides circumstances under which an entity should recognize events or transactions occurring after the balance sheet in its financial statements and identifies disclosures that an entity should make about events or transactions that occur after the balance sheet date. This statement is in effect for interim or annual financial reports ending after June 15, 2009. Adoption of SFAS 165 did not have a material impact on our financial position or results of operations.

In June 2009, the FASB issued SFAS No. 166,Accounting for Transfers of Financial Assets, (“SFAS 166”). This statement was issued as a means to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position; financial performance; and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. This statement takes effect as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. We are currently evaluating this new statement, but do not believe that it will have a significant impact on the determination or reporting of our financial results.

In June 2009, the FASB issued SFAS No. 167,Amendments to FASB Interpretation No. 46(R), (“SFAS 167”) which was issued to improve financial reporting by enterprises involved with variable interest entities. This statement addresses the effects of certain provisions of FASB Interpretation No. 46(R) and constituent concerns about the application of certain key provisions of FASB Interpretation No. 46(R), including those in which the accounting and disclosures do not always provide timely and useful information about an enterprises involvement in a variable interest entity. This statement takes effect as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim reporting periods thereafter. We are currently evaluating this new statement but do not believe that it will have a significant impact on the determination or reporting of our financial results.

In June 2009, the FASB issued SFAS No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, (“SFAS 168”) (FASB ASC 105). This statement officially dictates that the FASB Accounting Standards Codification will become the source of authoritative U.S. generally accepted accounting principles. Following this statement, new standards will no longer be issued in the form of statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. SFAS 168 is effective for financial statements issued for reporting periods that end after September 15, 2009. Adoption of this statement did not have a material impact on our financial positions or results of operations.

5. CONCENTRATIONS OF CREDIT RISK

At times during the three and six month periods ended June 30, 2009, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transaction with high-quality counterparties.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At June 30, 2009, we carried approximately $4.5 million in production receivables, of which approximately $3.9 million were production receivables due from a single customer, Countrymark Cooperative LLP (“Countrymark”). At June 30, 2008, we carried approximately $10.2 million in production receivables, of which approximately $8.1 million were production receivables from Countrymark. During the first quarter of 2009, we placed into operation an oil offload facility in the Illinois Basin that we believe will enable us to diversify the purchasers of our oil in the future if we choose to do so. Additionally, we believe the growth in our Appalachian Basin proved reserve base will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.

6. LONG-TERM DEBT

Our credit agreement is with KeyBank, as Administrative Agent; BNP Paribas, as Syndication Agent; Sovereign Bank, as Documentation Agent; and lenders from time to time parties thereto (the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The initial borrowing base was $75.0 million; however, the Senior Credit Facility provides that the revolving credit facility may be increased up to $200.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. Within that borrowing base, outstanding letters of credit are permitted up to $10.0 million. Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans. At our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to (a) LIBOR for one, two, three, six or nine months (“Adjusted LIBOR”) plus an applicable margin ranging from 100 to 175 basis points plus a commitment fee ranging from 25 to 37.5 basis points, or (b) the higher of KeyBank’s announced prime rate (“Prime Rate”) and the federal funds effective rate from time to time plus 0.5% in each case, plus an applicable margin ranging from 0 to 25 basis points plus a commitment fee ranging from 25 to 37.5 basis points. Interest is payable on the last day of each relevant interest period in the case of loans bearing interest at the Adjusted LIBOR and quarterly in the case of loans bearing interest at the Prime Rate. The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based

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on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. On or before March 1 and September 1 of each year, we are required to furnish to the lenders a reserve report evaluating our oil and gas properties as of the immediately preceding January 1 and July 1. The reserve report as of January 1 of each year must be prepared by one or more independent petroleum engineers approved by the Administrative Agent. Any re-determined borrowing base will become effective on the subsequent April 1 and October 1. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base.

On April 14, 2008, we entered into a First Amendment to the Senior Credit Facility (the “First Amendment”). The First Amendment provides that the borrowing base under the Senior Credit Facility was increased from $75.0 million to $90.0 million effective April 14, 2008. The increased borrowing base remained in effect until the next borrowing base re-determination date. The First Amendment also amended the Senior Credit Facility to provide that, upon an increase in the borrowing base, we will pay to the lenders a borrowing base increase fee equal to 25 basis points on the amount of any increase of the borrowing base over the highest borrowing base previously in effect, payable on the effective date of any such increase. In addition, the First Amendment amended the Senior Credit Facility with respect to our ability to enter into commodity and swap agreements. The First Amendment provided that we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. Prior to the First Amendment, the volumes for commodity swap agreements under the Senior Credit Facility could not exceed, as of the date the swap agreement was executed, 75% of the reasonably anticipated projected production from our proved developed producing reserves, for each of crude oil and natural gas for each month during the period in which the swap agreement was in effect for each of crude oil and natural gas, calculated separately.

The First Amendment also amended the Senior Credit Facility to provide that we may enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20.0 million and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate. Prior to the First Amendment, our interest rate swap agreements under the Senior Credit Facility were limited to 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.

On January 5, 2009, we entered into a Second Amendment to the Senior Credit Facility effective December 23, 2008 (the “Second Amendment”). The Second Amendment provided that the borrowing base under our Senior Credit Facility of $90.0 million will remain in effect until the next borrowing base re-determination date. Upon the completion of the sale of our Southwest Region properties on March 24, 2009, our borrowing base under the Senior Credit Facility was reduced to $80.0 million. In addition, the Second Amendment amended the Senior Credit Facility to amend the definition of “Alternate Base Rate”. The Second Amendment provided that the “Alternate Base Rate” means, for any day, a rate per annum equal to the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus¹ / ₂ of 1% and (c) (i) LIBOR plus (ii) the Applicable Margin for Euro Dollar Loans minus (iii) the Applicable Margin for ABR Loans each on such day. Prior to the Second Amendment, “Alternate Base Rate” meant, for any day, a rate per annum equal to the greater of (a) the Prime Rate in effect on such day and (b) the Federal Funds Effective Rate in effect on such day plus¹/₂ of 1%.

On April 24, 2009, we entered into a Third Amendment to Credit Agreement to the Senior Credit Facility effective as of April 20, 2009 (the “Third Amendment”) and amended certain provisions of our Senior Credit Facility. The Third Amendment provides that the borrowing base under our Senior Credit Facility of $80.0 million will remain in effect until the next borrowing base re-determination date. In addition, the Third Amendment amended the borrowing base utilization grid in the definition of “Alternate Base Rate.” The revised borrowing base utilization grid increases the margin interest rate for Eurodollar loans from a range of 1.00% to 1.75% per annum to a range of 1.75% to 2.50% per annum, increases the base margin rate from a set rate of 0.50% per annum to a range of 0.50% to 1.25% per annum, and increases the unused commitment fee rate from a range of 0.25% to 0.375% per annum to a range of 0.375% to 0.50% per annum. Rates charged from time to time under the borrowing base utilization grid within each applicable range are determined by our percentage of utilization of the then established borrowing base.

The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; enter into transactions with affiliates; create or acquire additional subsidiaries; incur indebtedness; sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions. The Senior Credit Facility also requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. Borrowings under the Senior Credit Facility have been used to finance our working capital needs and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under the Senior Credit Facility are secured by mortgages on the oil and gas properties of our subsidiaries located in the states of Illinois and Indiana. We are required to maintain liens covering our oil and gas properties representing at least 80% of our total value of all oil and gas properties.

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At June 30, 2009, we had $15.0 million borrowed under the Senior Credit Facility and had $65.0 million available for future borrowings.

In addition to our Senior Credit Facility, we may, from time-to-time in the normal course of business, finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and lines of credit consisted of the following at June 30, 2009 and December 31, 2008:

	June 30, 2009			December 31, 2008
	($ in Thousands)			($ in Thousands)
Senior Credit Facility1	$	15,000		$	15,000
Other Loans and Notes Payable		324			—
Total Debts		15,324			15,000
Less Current Portion of Long-Term Debt		(324	)		—
Total Long-Term Debts	$	15,000		$	15,000

¹ The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans.

7. FAIR VALUE OF FINANCIAL AND DERIVATIVE INSTRUMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we enter into oil and natural gas commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparty. We do not enter into these arrangements for speculative trading purposes. As of June 30, 2009 and June 30, 2008, our oil and natural gas derivative commodity instruments consisted of fixed rate swap contracts and collars. These instruments do not qualify as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as other income or expense.

Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a calculation period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

We enter into the majority of our derivative arrangements with two counterparties and have a netting agreement in place with each of these counterparties. We do not obtain collateral to support the agreements, but monitor the financial viability of our counterparties and believe our credit risk is minimal on these transactions.

None of our derivatives qualify for hedge accounting but are, to a degree, an economic offset to our oil and natural gas price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all unrealized and realized gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense).

We received net cash receipts of $1.5 million and $9.9 million under these commodity derivative instruments during the three and six month periods ended June 30, 2009. We made net payments of approximately $7.8 million and $11.1 million under these commodity derivative instruments during three and six month periods ended June 30, 2008. During the first quarter of 2009, we redeemed our oil hedges related to production in 2011 for net cash proceeds of approximately $4.6 million. Unrealized losses associated with these derivative instruments from continuing operations amounted to $12.1 million and $65.9 million for the three month periods ended June 30, 2009 and 2008, and $14.8 million and $78.9 million for the six month periods ending June 30, 2009 and 2008, respectively. Both realized and unrealized gains and losses are included in Gain (Loss) on Derivatives, Net on our Consolidated Statements of Operations.

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The following table summarizes the location and amounts of gains and losses on derivative instruments, none of which are designated or qualify as hedges, in our accompanying Consolidated Statements of Operations for the three and six month periods ended June 30, 2009 and 2008 ($ in thousands):

	Three Months Ended June 30, 2009								Three Months Ended June 30, 2008
	Realized Gains (Losses)		Unrealized Gains (Losses)			Total			Realized Gains (Losses)			Unrealized Gains (Losses)			Total
Gain (Loss) on Derivatives, Net:
Reclassification of settled contracts included in prior periods unrealized gains (losses)	$	—	$	(2,466	)	$	(2,466	)	$	—		$	4,819		$	4,819
Mark-to-market fair value adjustments (b)		—		(9,598	)		(9,598	)		—			(70,675	)		(70,675	)
Settlement of contracts (a)		1,544		—			1,544			(7,783	)		—			(7,783	)
Total	$	1,544	$	(12,064	)	$	(10,520	)	$	(7,783	)	$	(65,857	)	$	(73,640	)

(a) These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.

(b) Includes mark-to-market on interest rate swap of $163 and $0 for the three months ended June 30, 2009 and 2008, respectively.

	Six Months Ended June 30, 2009								Six Months Ended June 30, 2008
	Realized Gains (Losses)		Unrealized Gains (Losses)			Total			Realized Gains (Losses)			Unrealized Gains (Losses)			Total
Gain (Loss) on Derivatives, Net:
Reclassification of settled contracts included in prior periods unrealized gains (losses)	$	—	$	(4,496	)	$	(4,496	)	$	—		$	5,569		$	5,569
Mark-to-market fair value adjustments (b)		—		(10,268	)		(10,268	)		—			(84,425	)		(84,425	)
Settlement of contracts (a)		9,888		—			9,888			(11,064	)		—			(11,064	)
Total	$	9,888	$	(14,764	)	$	(4,876	)	$	(11,064	)	$	(78,856	)	$	(89,920	)

(a) These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.

(b) Includes mark-to-market on interest rate swap of $214 and ($308) for the six months ended June 30, 2009 and 2008, respectively.

Our derivative instruments are recorded on the balance sheet as either an asset, or a liability, measured at its fair value. The fair value associated with our derivative instruments from continuing operations was a liability of approximately $0.5 million and a liability of $108.4 million at June 30, 2009 and 2008, respectively. The fair value is based on the valuation methodologies of our counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

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Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2009 consisted of:

Period	Contract Type	Volume	Average Derivative Price	Fair Market Value ($ in Thousands)
Oil
2009	Swaps	100,000 Bbls	$63.29	$	(824	)
2009	Collars	200,000 Bbls	$64.03 – 83.02	$	(261	)
2010	Swaps	180,000 Bbls	$62.20	$	(2,348	)
2010	Collars	408,000 Bbls	$62.94 – 86.85	$	(657	)
2011	Collars	156,000 Bbls	$65.00 – 100.50	$	167
	Total	1,044,000 Bbls		$	(3,923	)
Natural Gas
2009	Swaps	60,000 Mcf	$6.00	$	30
2009	Collars	600,000 Mcf	$6.80 – 8.71	$	1,212
2010	Swaps	120,000 Mcf	$6.00	$	60
2010	Collars	1,200,000 Mcf	$7.25 – 9.99	$	1,732
2011	Collars	1,080,000 Mcf	$7.33 – 12.29	$	1,272
2012	Collars	360,000 Mcf	$6.00 – 7.38	$	48
	Total	3,420,000 Mcf		$	4,354

As of June 30, 2009, we had entered into an interest rate swap derivative instrument which hedged our interest rate risk associated with changes in LIBOR on $20.0 million of notional value. We use the interest rate swap agreement to manage the risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. Under our interest rate swap agreement, we agree to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount. The interest rate under the swap is 4.15% and the agreement expires in November 2010. The fair value of the swap at June 30, 2009 was a liability of $1.0 million, an increase of $163,000 and $214,000 for the three and six month periods ended June 30, 2009, based on current LIBOR quotes. On June 30, 2008, the interest rate swap was considered to be ineffective. We have accounted for the hedge by recording the unrealized gains for the three and six months ended June 30, 2009 in Gain (Loss) on Derivatives, Net on our Consolidated Statements of Operations.

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The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008 is summarized below ($ in thousands).

	June 30, 2009			December 31, 2008
Short-Term Derivative Assets:
Crude Oil – Swaps	$	—		$	1,821
Crude Oil – Collars		528			5,241
Natural Gas – Swaps		60			—
Natural Gas—Collars		2,078			1,091
Total Short-Term Derivative Assets	$	2,666		$	8,153
Long-Term Derivative Assets:
Crude Oil – Swaps	$	—		$	—
Crude Oil – Collars		490			5,511
Natural Gas – Swaps		30			—
Natural Gas – Collars		2,186			2,050
Total Long-Term Derivative Assets	$	2,706		$	7,561
Total Derivative Assets	$	5,372		$	15,714
Short-Term Derivative Liabilities:
Crude Oil – Swaps	$	(1,999	)	$	—
Crude Oil – Collars		(1,117	)		—
Natural Gas – Swaps		—			—
Natural Gas – Collars		—			—
Total Short-Term Derivative Liabilities	$	(3,116	)	$	—
Long-Term Derivative Liabilities:
Crude Oil – Swaps	$	(1,173	)	$	(303	)
Crude Oil – Collars		(653	)		(2	)
Natural Gas – Swaps		—			—
Natural Gas – Collars		—			—
Interest Rate – Swap		(957	)		(1,171	)
Total Long-Term Derivative Liabilities	$	(2,783	)	$	(1,476	)
Total Derivative Liabilities	$	(5,899	)	$	(1,476	)

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Adoption of SFAS 157

Effective January 1, 2008, we adopted SFAS 157 (FASB ASC 820), which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy defined by SFAS 157 are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Level 2—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At March 31, 2009, we have no significant Level 3 measurements.

The following table presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis, as set forth in SFAS 157 ($ in thousands):

	Total Carrying Value as of June 30, 2009			Fair Value Measurements at June 30, 2009 Using:
				Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivatives – commodity swaps and collars	$	431		$	—	$	431		$	—
– interest rate swaps	$	(958	)	$	—	$	(958	)	$	—

8. INCOME TAXES

We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes (“SFAS 109”) (FASB ASC 740). Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

Income tax included in continuing operations was as follows ($ in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Income Tax Benefit	$	(5,841	)	$	(26,061	)	$	(7,045	)	$	(30,687	)
Effective Tax Rate		38.2	%		40.4	%		39.5	%		40.4	%

Effective August 1, 2007, we adopted FASB Interpretation 48, Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement 109 (“FIN 48”) (FASB ASC 740), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attribute

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for the financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Our practice is to recognize interest related to income tax expense in Interest Expense and penalties in General and Administrative expense.

We also adopted FASB Staff Position FIN 48-1, Definition of Settlement in FASB Interpretation 48 (“FSP FIN 48-1”) (FASB ASC 740-10-25) as of August 1, 2007. FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal and it is remote that the taxing authority would reexamine the tax position in the future.

The adoption of FIN 48 and FSP FIN 48-1 did not have a significant effect on our financial position, results of operations or cash flows.

At December 31, 2008, we had net operating loss (“NOL”) carryforwards of $8.1 million that expire between 2027 and 2028. Our management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets, which consist primarily of NOL’s and deductible temporary differences. Management has determined, based on positive and negative evidence examined and anticipated future taxable income, that it is now more likely than not that these deferred tax assets will likely be realized in the future and, thus, determined that it is appropriate to present our deferred tax assets without a valuation allowance.

We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States Federal jurisdiction and in many state jurisdictions. We are subject to U.S. Federal income tax examinations and to various state tax examinations for periods after August 1, 2007.

9. CAPITAL STOCK

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2009 and December 31, 2008, we had 36,844,312 and 36,589,712 shares of common stock outstanding, respectively.

On May 5, 2008, we completed a public offering of 9.775 million shares of common stock at an offering price of $20.75 per share. These shares included 5.775 million shares offered by us (which includes 1.275 million shares sold pursuant to the exercise of an over-allotment option granted to the underwriters’ of the offering) and 4.0 million shares sold by certain selling stockholders. The net proceeds to us from the underwritten public offering, after underwriting discounts and offering expenses of approximately $6.8 million, were approximately $113.0 million. We used a portion of the net proceeds from this offering to fund, in part, our capital expenditure program for 2008, including our enhanced oil recovery project in the Lawrence Field in Lawrence County, Illinois (which we refer to as our ASP project) and our leasing and drilling activities in the Marcellus Shale and for other corporate purposes. Additionally, we used a portion of the net proceeds to repay borrowings under our Senior Credit Facility and made investments in short-term, investment grade, interest-bearing securities. We will re-borrow amounts from time-to-time under our Senior Credit Facility as capital expenditures exceed overnight investments and cash flow from operations in periods subsequent to the offering.

10. EMPLOYEE BENEFIT AND EQUITY PLANS

401(k) Plan

We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our matching contributions to the plan are discretionary and we ceased to provide a matching contribution to the 401(k) plan beginning in January 2009. During June 2009, our management made the decision to resume our matching contributions to the 401(k) plan beginning in July 2009. Our contributions to the plan were $39,000 and $76,000 for the three months ended June 30, 2009 and 2008 and $50,000 and $129,000 for the six months ended June 30, 2009 and 2008, respectively.

Equity Plans

In December 2004, the FASB issued SFAS 123(R), Share-Based Payment (“SFAS 123R”) (FASB ASC 718), which is a revision of SFAS 123, Accounting for Stock Based Compensation (“SFAS 123”). SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their grant-date fair values, using prescribed option-pricing models. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period.

Effective August 1, 2007, we adopted SFAS 123R’s fair value method of accounting for share-based payment. Prior to August 1, 2007, we did not have any share-based payments to employees or directors.

SFAS 123R also requires the benefits of tax deductions in excess of recognized compensation to be reported as a financing cash flow, rather than as an operating cash flow as required under previous literature. This requirement reduces net operating cash flows and increases net financing cash flows in periods after adoption. There were no tax benefits recognized during the three and six month periods ended June 30, 2009 and 2008.

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2007 Long-Term Incentive Plan

We have granted stock options, stock appreciation rights and restricted stock awards to various employees and non-employee directors under the terms of our 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our Board of Directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are: selecting participants to receive awards; determining the form; amount and other terms and conditions of awards; interpreting the provisions of the Plan or any award agreement; and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees, are intended to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.

All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Market on the day the award was granted. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.

Stock Options

During the six month period ended June 30, 2009, the Compensation Committee awarded nonqualified options to purchase a total of 68,888 shares of our common stock to one employee and four non-employee directors. The nonqualified stock option granted to our employee has an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vests and become exercisable on the third anniversary of the grant date, provided that the option holder remains our employee until that date. The nonqualified stock options granted to our non-employee directors have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable in one-third increments on the first, second and third year anniversaries of the date of grant. All options will vest and become immediately exercisable upon a “change in control” of us, as such term is defined in the Plan.

Stock options represent the right to purchase shares of common stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan.

A summary of the stock option activity is as follows:

	Shares		Weighted Average Exercise Price
Outstanding on December 31, 2008	993,700		$	13.75
Granted	68,888			4.84
Exercised	—			—
Forfeited	(123,751	)		11.04
Outstanding on June 30, 2009	938,837		$	13.45

Stock-based compensation expense relating to stock options for the three and six month periods ended June 30, 2009 totaled $621,000 and $1.1 million, respectively, compared to $736,000 and $1.1 million, respectively, for the same periods in 2008. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative expense.

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A summary of the status of our issued and outstanding stock options as of June 30, 2009 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding At 6/30/09	Weighted-Average Remaining Contractual Life (Years)	Weighted-Average Exercise Price		Number Exercisable At 6/30/09	Weighted-Average Exercise Price
$	9.50	125,000	8.36	$	9.50	41,667	$	9.50
$	9.99	389,749	8.36	$	9.99	58,749	$	9.99
$	13.56	57,200	8.64	$	13.56	—		—
$	22.34	50,000	8.80	$	22.34	—		—
$	23.00	75,000	8.85	$	23.00	—		—
$	23.88	75,000	3.89	$	23.88	—		—
$	23.28	10,000	4.03	$	23.28	—		—
$	21.68	15,000	4.06	$	21.68	—		—
$	19.92	26,000	4.12	$	19.92	—		—
$	21.10	30,000	4.15	$	21.10	—		—
$	5.60	17,000	4.37	$	5.60	—		—
$	3.24	7,500	4.54	$	3.24	—		—
$	5.04	61,388	4.85	$	5.04	—		—
	Total	938,837	7.38	$	13.45	100,416	$	9.79

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at June 30, 2009 were 7.38 years and $0, respectively. As of June 30, 2009, unrecognized compensation expense related to stock options totaled approximately $2.8 million, which will be recognized over a weighted average period of 1.67 years.

Stock Appreciation Rights

Stock appreciation rights (“SARs”) represent the right to receive cash or shares of common stock in the future equivalent to the difference between the fair market value at the time of exercise and the exercise price. The Compensation Committee awarded 109,500 SARs during 2008, which have an exercise price of $13.56, the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable on the third anniversary of the grant date, provided that the holder remains our employee until that date. The SARs also provide that all unvested SARs vest and become immediately exercisable upon a “change in control” of us, as such term is defined in the Plan. The outstanding SARs issued may only be exercised for cash settlement.

		Outstanding				Exercisable
Strike Price		Number of SARs Granted	SARs Forfeited or Cancelled	SARs Outstanding	Weighted-Average Remaining Contractual Life (Years)	Weighted-Average Strike Price		SARs	Weighted-Average Exercise Price
$	13.56	109,500	36,000	73,500	8.64	$	13.56	—	—
	Total	109,500	36,000	73,500	8.64	$	13.56	—	—

Restricted Stock Awards

During the six month period ended June 30, 2009, the Compensation Committee issued 261,850 shares of restricted common stock to 15 employees, with all restrictions on transfer associated with such shares scheduled to terminate in February 2012. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Market on the date of the grant. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restrictions on the stock lapse immediately upon a “change in control” of us, as such term is defined in the Plan. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period. As of June 30, 2009, total unrecognized compensation cost related to the restricted common stock grant was approximately $810,000.

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A summary of the restricted stock activity for the six months ended June 30, 2009 is as follows ($ in thousands, except per share data):

	Number of Shares		Weighted Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2008	20,000		$	23.00
Awards	261,850			2.05
Forfeitures	(7,250	)		2.05
Restrictions released	—			—
Restricted stock awards, as of June 30, 2009	274,600		$	3.58

11. COMMITMENTS AND CONTINGENCIES

Legal Reserves

At June 30, 2009, our Consolidated Balance Sheet included approximately $669,000 in reserve for legal accruals relating to legal costs and expenses associated with lawsuits filed relating to our Marcellus Shale leasing activities in the Commonwealth of Pennsylvania and the legal costs and expenses associated with the class action lawsuit pending in the United States District Court for the Southern District of Illinois. At December 31, 2008, our Consolidated Balance Sheet included $327,000 in reserve for various legal matters and proceedings. The accrual of reserves for legal matters is included in Accrued Expenses on the Consolidated Balance Sheet. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur an additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on our consolidated financial position or results of operations, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Drilling and Development

At June 30, 2009, we had three drilling commitments in our Appalachian Basin. The first commitment requires us to drill five natural gas wells and complete one natural gas well, which has already been started, by April, 2014. We estimate an average investment in each well to be $1.9 million for a total drilling commitment of $11.4 million over the next 5 years. Our second drilling commitment requires us to drill one natural gas well by December 11, 2009 at an estimated cost of $1.9 million. Our third drilling commitment requires that we build one well location and proceed with the drilling of one vertical test well, subject to rig availability, at an estimated cost of $1.9 million. If for any reason we do not meet this commitment we may be required to pay an amount equal to $100,000 upon the request of the landowner(s).

Leasing

At June 30, 2009, we had committed to make three installment payment commitments on oil and gas interests that were previously leased. The first commitment provides that we pay $350 per mineral acre for 5,722 acres, or a total commitment of $2.0 million, in 2012. The second commitment requires that we pay $250 per mineral acre for 5,761 acres, or $1.4 million, in each of the next three years for a total commitment of $4.3 million. The third commitment requires that we pay $350 per mineral acre for 762 acres, or $267,000, in each of the next four years for a total commitment of $1.1 million. These amounts have been recorded on the balance sheet as Other Deposits and Liabilities.

Environmental

Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except for contingent liabilities associated with the enforcement action initiated by the U.S. EPA and the putative class action litigation filed in the U.S. District Court of the Southern District of Illinois relating to alleged H ₂ S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.

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Contract Wells

In March 2004, we purchased from Standard Steel, LLC certain contractual rights associated with various gas purchase contracts relating to 19 natural gas wells located in Westmoreland County, Pennsylvania. Under the terms of the contracts, we buy 100.0% of the production from these wells from third parties at contracted, fixed prices. The prices we pay may range from $1.10 per Mcf to 55.0% of the market price, plus a $0.10 per Mcf surcharge. There is no loss on these commitments. We have recorded the gross revenue and costs in the Consolidated Statements of Operations. We sell the natural gas extracted from these contract wells to parties unrelated to these natural gas wells and contracts.

Letters of Credit

At June 30, 2009, we had posted $843,000 in various letters of credit to secure our drilling and related operations.

Lease Commitments

At June 30, 2009, we had lease commitments for two different office locations. Rent expense has been recorded in general and administrative expense for continued operations as $88,000 and $176,000 for the three and six month periods ended June 30, 2009, respectively, and $62,000 and $84,000 for the three and six month periods ended June 30, 2008, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):

2009	$	225
2010		452
2011		454
2012		456
2013		479
Thereafter		—
Total	$	2,066

PennTex Illinois and Rex Operating—H2S Class Action Litigation

PennTex Resources Illinois, Inc. (“PennTex Illinois”) and Rex Energy Operating Corp. (“Rex Operating”) are defendants in a class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois. This action was commenced on October 17, 2006, by plaintiffs Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled owned or operated by PennTex Illinois and Rex Operating has resulted in “serious contamination” of the class area with H₂S. The complaint asserts several causes of action, including violation of the Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint was amended in March 2007 to add a claim for alleged violation of Section 7002(a)(1) of the Resource Conservation And Recovery Act. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area. PennTex Illinois and Rex Operating have filed a joint answer to the amended complaint denying virtually all of the allegations in the amended complaint and asserting affirmative defenses thereto.

The plaintiffs filed an amended motion for class certification on January 22, 2008 and PennTex Illinois and Rex Operating filed a joint motion opposing class certification on February 22, 2008. On December 19, 2008, the district court issued a preliminary ruling on certification, indicating its conclusion that several of the class action prerequisites were met and that it was likely to certify a class to adjudicate two issues relating to the emission of H₂S in the putative class area, while reserving all remaining issues for subsequent individual adjudications. The district court denied the plaintiffs’ motion to certify a class in reference to the plaintiffs’ medical monitoring claim. The district court requested that the plaintiffs submit a revised class definition consistent with its order, which was submitted by the plaintiffs on January 16, 2009. On January 28, 2009, PennTex Illinois and Rex Operating filed an objection to the plaintiffs’ revised class definition and requested that the district court deny the plaintiffs’ motion for class certification.

On February 26, 2009, the district court issued an order approving the geographic scope of the plaintiffs’ revised class definition. In its order, the district court denied plaintiffs’ request to include all residents and landowners within the geographic area of the class owning property since October 17, 2006, the date the lawsuit was filed, and limited the class to only current property owners. On March 11, 2009, PennTex Illinois and Rex Operating filed a petition for leave to appeal with the United States Court of Appeals for the Seventh Circuit to appeal the district court’s class certification order on an interlocutory basis. On April 2, 2009, the United States Court of Appeals for the Seventh Circuit denied the petition for leave to appeal filed by PennTex Illinois and Rex Operating.

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On July 21, 2009, the district court issued an order approving the plaintiffs’ proposed class notification plan and providing that plaintiffs have 30 days from the date of the order to mail the approved class notice to the class members. The order provides that class members have until October 16, 2009 to decide whether to opt out of the class. The district court further ordered that a trial date and discovery schedule be set by a magistrate judge of the district.

We intend to vigorously defend against the claims that have been asserted against PennTex Illinois and Rex Operating in this lawsuit. Because this lawsuit is in its initial phase, however, and because it is usually difficult to predict the outcome of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or to estimate the amount or the range of potential loss should the outcome be unfavorable to us.

PennTex Resources—Wood Arbitration and Confirmation of Arbitration Award

PennTex Resources, L.P. (“PennTex Resources”) was a litigant in an appeal in the United States Court of Appeals for the Fifth Circuit entitled “Scott Y. Wood v. PennTex Resources, L.P., Case No. 08-20462.” The case was an appeal of a final judgment that was signed on June 27, 2008 by the United States District Court for the Southern District of Texas, Houston Division. The final judgment confirmed an award issued on August 20, 2007 by an arbitration panel convened by the American Arbitration Association in Houston, Texas. The principal claim in the arbitration proceeding was PennTex Resources’ claim that Scott Y. Wood (“Wood”), and his wholly owned corporation, ERG Illinois Holdings, Inc., should be ordered to comply with a “claim release obligation” contained in a stock purchase agreement signed in 2005 that required Wood, under certain designated circumstances, to dismiss or release the individual claims that he was prosecuting against Tsar Energy II, LLC (“Tsar”) and Richard A. Cheatham (“Cheatham”) in the 334th Judicial District Court of Harris County, Texas (the “Tsar Case”). PennTex Resources became obligated to file this arbitration proceeding seeking to enforce Wood’s “claim release obligation” by reason of an agreement that PennTex Illinois and PennTex Resources entered into on March 2, 2006 with Tsar and Cheatham in order to resolve certain procedural issues relating to the Tsar Case.

On August 20, 2007, the arbitration panel ordered Wood to promptly provide PennTex Resources with a signed release or dismissal of his claims filed in the Tsar Case and required Wood to pay PennTex Resources a total of $141,003. On September 8, 2008, Wood filed an appeal with the United States Court of Appeals for the Fifth Circuit requesting the appellate court to reverse the district court’s prior decision compelling Wood to participate in the arbitration proceeding and its order confirming the arbitration award. In connection with his appeal, Wood deposited into the registry of the district court an amount equal to the judgment against him and a fully executed release of his claims against Tsar and Cheatham. On October 10, 2008, PennTex Resources filed its response brief opposing Wood’s appeal and requesting the appellate court to affirm the district court’s final judgment against Wood. On April 23, 2009, the United States Court of Appeals for the Fifth Circuit held that the district court properly ordered Wood to arbitration and affirmed the district court’s confirmation of the arbitration award. In the event that Wood files an appeal of the decision of the United States Court of Appeals for the Fifth Circuit, we intend to continue to vigorously oppose Wood and we believe that the likelihood of an unfavorable outcome of this matter is remote.

Litigation Related to Proposed Oil and Gas Leases in Westmoreland and Clearfield Counties, Pennsylvania

On July 2, 2009, Rex Energy Corporation and its wholly-owned subsidiary, Rex Energy I, LLC (“Rex I”), were named as defendants in a proposed class action lawsuit filed on that date in the Court of Common Pleas of Westmoreland County, Pennsylvania (the “Snyder Case”). The named plaintiffs are Clyde J. Snyder and Janelle Snyder, William L. Snyder II, and Ray E. White and Sandra K. White, who have sued on behalf of themselves and all persons who are alleged to be “similarly situated” to such named plaintiffs by reason of having signed in 2008 alleged oil and gas lease agreements with Rex I relating to property located in Westmoreland County, Pennsylvania or elsewhere in Pennsylvania as to which Duncan Land & Energy, Inc. (“Duncan Land”) allegedly acted as land agent for Rex I or Rex Energy Corporation, and as to which the rental or bonus payments described in the alleged oil and gas leases have not been paid. The alleged oil and gas leases at issue in the lawsuit are on forms that provide for execution by Rex I. The plaintiffs’ filing of the complaint followed Rex I’s election not to execute or accept the plaintiffs’ proposed oil and gas leases and Rex I’s written notification to the plaintiffs and other proposed lessors that their proposed oil and gas leases had been rejected.

The complaint in the Snyder Case generally asserts that a binding contract was formed between Rex I and the plaintiffs, and other persons within the proposed class, when “defendants’ landmen/Duncan Land” presented a form of proposed oil and gas lease to each such person, and each such person signed the proposed oil and gas lease form and delivered the executed proposed lease to “defendants’ landmen/Duncan Land.” The plaintiffs make this assertion notwithstanding that none of defendants’ employees are believed to have negotiated directly with any of the named plaintiffs or proposed class members. In addition, the plaintiffs make this assertion notwithstanding that Duncan Land acted as an independent contractor for Rex I pursuant to an agreement that explicitly states that Duncan Land has no authority to bind Rex I to an oil and gas lease, and notwithstanding that each of the proposed leases on its face contemplates the execution of the lease by Rex I, which the defendants will assert put each of the lessors of the proposed leases on notice that no binding lease would be created unless Rex I elected to accept and sign each of the proposed oil and gas leases. Despite the foregoing, the complaint in the Snyder Case alleges that “defendants’ landmen/Duncan Land” had the authority to offer and/or accept each of the proposed oil and gas leases on behalf of Rex I, and also pleads causes of action against Rex I and Rex Energy Corporation premised on theories of breach of contract, tortious interference with contract and civil conspiracy. The plaintiffs seek a

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judgment declaring that each of the proposed oil and gas leases transferred an interest in real estate to Rex I, and that each of such proposed leases constitutes a binding contract enforceable against Rex I and Rex Energy Corporation, and further declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees.

We are evaluating the plaintiffs’ recently-filed complaint in the Snyder Case, and considering the appropriate actions to take in response thereto. We believe that plaintiffs’ claims are without merit. We intend to vigorously defend against the plaintiffs’ attempts to certify the proposed class and to vigorously defend against all of the claims that have been asserted against Rex I and Rex Energy Corporation in this lawsuit. Because this lawsuit was only recently initiated, we are currently unable to express an opinion with respect to the likelihood of an unfavorable outcome. However, because we have information that allows us to identify the total number of proposed leases that Rex I has rejected that could potentially be within the scope of the proposed class as described in the complaint, we are able to estimate the aggregate acreage and aggregate amount of prepaid rentals or bonuses that could potentially be at issue in the event that the plaintiffs were to be successful in their efforts to certify their proposed class, and in thereafter obtaining a judgment that each of the proposed oil and gas leases constitutes a binding obligation of Rex I or Rex Energy Corporation, and assuming that all persons who signed rejected oil and gas leases related to lands located in Westmoreland County were to elect to submit claims in the Snyder Case. Specifically, we estimate that in such event the amount in controversy would encompass rentals or bonuses for oil and gas leases covering approximately 7,362 acres and a potential obligation for payment of prepaid rentals or bonuses totaling approximately $17.7 million. We are unable to estimate the amount or range of any potential losses that might be associated with other aspects of the plaintiffs’ breach of contract claims in the Snyder Case, or with respect to the plaintiffs’ tort claims in the event of an unfavorable outcome with respect thereto.

Rex I is also a defendant in six other lawsuits involving oil and gas leasing activity that were filed during the Winter of 2008 and the Spring of 2009 by individual plaintiffs in the Court of Common Pleas of Westmoreland County, Pennsylvania. These lawsuits involve similar claims and requests for relief as those made in the Snyder Case described above. The plaintiffs who have filed these other lawsuits are represented by an attorney who is also representing the named plaintiffs in the Snyder Case. In general, the complaints in these other lawsuits assert that the plaintiffs, by executing and delivering their respective proposed oil and gas leases to Rex I, sold to Rex I the right to produce oil and gas from their respective properties and created a binding obligation on Rex I to pay the rental consideration set forth in each of the proposed oil and gas leases. The plaintiffs make this assertion notwithstanding that each of the proposed leases specifically contemplated the execution of the lease by Rex I, and notwithstanding that Rex I elected not to accept or sign each of the proposed oil and gas leases. The complaints in these other lawsuits seek a judgment in favor of each set of plaintiffs in the amount of the rental or bonus consideration described in each of the proposed oil and gas leases, plus interest thereon and costs. We believe that the plaintiffs’ claims in these other lawsuits are also without merit, and we intend to vigorously defend against the claims asserted in each of these other lawsuits. Because these other lawsuits are in the initial stages of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome. In the event that the plaintiffs in each of these other lawsuits were to obtain a judgment that their respective proposed oil and gas lease constitutes a binding obligation of Rex I, we estimate that Rex I’s resulting responsibility for rentals or bonuses for the proposed oil and gas leases would cover a total of approximately 552 acres and amount to approximately $1.4 million. We are unable to estimate the amount or range of any other potential losses in the event of an unfavorable outcome on the plaintiffs’ claims in these other lawsuits.

On June 5, 2009, R.E. Gas Development, LLC (“R.E. Gas”), a wholly owned subsidiary of the Company, was named as a defendant in a lawsuit that was filed on that date in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Liegey Case”). The Liegey Case was brought by eight individuals who signed proposed oil and gas leases relating to approximately 127 acres of jointly-owned property located in Clearfield County, Pennsylvania. R.E. Gas elected not to accept the plaintiffs’ proposed oil and gas lease, and as a result, did not pay to each of the plaintiffs the rental consideration set forth in the lease. The complaint in the Liegey Case asserts that binding contracts between R.E. Gas and the plaintiffs were created when each of the plaintiffs executed a proposed oil and gas lease and delivered the executed proposed lease to a representative of Western Land Services, Inc. The complaint in the Liegey Case asserts causes of action against R.E. Gas premised on theories of breach of contract, unjust enrichment and detrimental reliance. The complaint seeks a judgment in favor of the plaintiffs in the amount of $397,933.75, plus interest, costs and attorneys’ fees. We intend to vigorously defend against these claims; however, because this lawsuit is in the initial stages of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome. In the event that the plaintiffs were successful in the Liegey Case, we estimate that R.E. Gas would be required to pay the plaintiffs an amount no greater than the damages sought in the plaintiffs’ complaint, plus interest, costs and attorneys’ fees.

Other

In addition to the Asset Retirement Obligation discussed in Note 3, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. These amounts total $302,000 at June 30, 2009 and December 31, 2008 and are included in Other Liabilities on our consolidated balance sheet.

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12. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

On March 24, 2009, we completed the sale of certain of our oil and gas leases, wells and related assets predominantly located in the Permian Basin in the states of Texas and New Mexico. We received net cash proceeds of approximately $17.3 million, which may be adjusted by certain post-closing adjustments, plus the assumption of certain liabilities, based on an effective date of October 1, 2008. Upon closing of the sale, we used the proceeds to pay down our long-term borrowings on our Senior Credit Facility.

Pursuant to the accounting rules for discontinued operations, these assets were classified as Assets Held for Sale on our Balance Sheet as of December 31, 2008, and results of operations are reflected in discontinued operations in our Consolidated Statements of Operations. At March 31, 2009, we recorded a loss on sale of assets of approximately $425,000 in our Consolidated Statement of Operations. Upon closing of the sale, we recorded severance wages in discontinued operations of approximately $167,000 for our former employees in the Southwest Region. Summarized financial information for discontinued operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the discontinued operations were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.

	For the Three Months Ended June 30, ($ in Thousands, Except per Share Data)					For the Six Months Ended June 30, ($ in Thousands, Except per Share Data)
	2009		2008			2009			2008
Revenues:
Oil and Natural Gas Sales	$	—	$	2,122		$	193		$	4,107
Other Revenue		—		111			—			193
Total Operating Revenue		—		2,233			193			4,300
Costs and Expenses:
Production and Lease Operating Expense		—		617			237			1,139
General and Administrative Expense		—		207			(97	)		473
Exploration Expense of Oil and Gas Properties		—		(13	)		—			1,121
Depreciation, Depletion, Amortization and Accretion		—		709			—			1,420
Loss on Sale of Assets		—		—			—			41
Loss on Derivatives		—		—			(558	)		—
Other Income		—		(1	)		—			(2	)
Total Costs and Expenses		—		1,519			(418	)		4,192
Income from Discontinued Operations Before Income Tax				714			611			108
Income Tax Expense		—		288			288			44
Income from Discontinued Operations, net of taxes	$	—	$	426		$	323		$	64
Earnings per Common Share:
Basic and Diluted Income	$	—	$	0.01		$	0.01		$	0.00
Production:
Crude Oil (Bbls)		—		10,362			7,507			23,369
Natural Gas (Mcf)		—		86,958			61,661			179,454
Total (BOE)		—		24,855			17,784			53,278

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13. EARNINGS PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period. Diluted income per common share includes the speculative exercise of stock options and SARs, given that the hypothetical effect is not anti-dilutive. Due to our net loss from continuing operations for the three and six months ended June 30, 2009, we excluded all 938,837 of outstanding stock options and 73,500 of SARs because the effect would have been anti-dilutive to the computations. Due to our net loss from continuing operations for the three and six months ended June 30, 2008, we excluded all 1.2 million of outstanding stock options and 109,500 SARs because the effect would have been anti-dilutive to the computations. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Numerator:
Net Loss From Continuing Operations	$	(9,437	)	$	(38,387	)	$	(10,784	)	$	(45,198	)
Net Income From Discontinued Operations		—			426			323			64
Net Loss		(9,437	)		(37,961	)		(10,461	)		(45,134	)
Denominator:
Weighted Average Common Shares Outstanding – Basic		36,846			34,349			36,789			32,572
Effect of Dilutive Securities:
Employee Stock Options and SARs		—			—			—			—
Weighted Average Common Shares Outstanding – Diluted		36,846			34,349			36,789			32,572
Earnings per Common Share:
Basic – Net Loss From Continuing Operations	$	(0.26	)	$	(1.12	)	$	(0.29	)	$	(1.39	)
– Net Income From Discontinued Operations		0.00			0.01			0.01			0.00
– Net Loss	$	(0.26	)	$	(1.11	)	$	(0.28	)	$	(1.39	)
Diluted – Net Loss From Continuing Operations	$	(0.26	)	$	(1.12	)	$	(0.29	)	$	(1.39	)
– Net Income From Discontinued Operations		0.00			0.01			0.01			0.00
– Net Loss	$	(0.26	)	$	(1.11	)	$	(0.28	)	$	(1.39	)

14. RELATED PARTY

Pursuant to the terms of the PEA signed with Williams, as discussed in Note 2, we agreed, with Williams, to form RW Gathering, LLC (“RW Gathering”), a Delaware limited liability company, to own any gas gathering assets which we agree to jointly construct in order to facilitate the development of our project area. The initial members of RW Gathering are Williams Production Appalachia, LLC and R.E. Gas Development, LLC, our wholly owned subsidiary, with each party owning an equal interest in the company. R.E. Gas Development, LLC will serve as the manager of RW Gathering until December 31, 2009. Beginning on January 1, 2010, Williams Production Appalachia, LLC will be the manager of the company. We own 50% of RW Gathering and have the ability to exercise significant influence over its operating and financial policies, therefore we account for this investment via the equity method. Under the equity method, we recorded our investment in RW Gathering of $506,000 on the Consolidated Balance Sheet as Investment in RW Gathering. Our share of income or loss will be recorded on the Statement of Operations.

As of June 30, 2009, we recorded a receivable due from RW Gathering of approximately $506,000. This amount directly relates to the reimbursement of costs incurred for assets that we contributed to the partnership. This amount is presented on our Consolidated Balance Sheet as Related Party Receivables. No other related party transactions took place during the three or six month periods ended June 30, 2009.

15. SUBSEQUENT EVENT

We have evaluated subsequent events through August 3, 2009, the date that our financial statements were issued. On July 2, 2009, we were named as defendants, along with our wholly-owned subsidiary, Rex Energy I, LLC, in a proposed class action lawsuit filed on that date in the Court of Common Pleas of Westmoreland County, Pennsylvania. Information relating to the proposed class action lawsuit is contained in Note 11, under the headingLitigation Related to Proposed Oil and Gas Leases in Westmoreland and Clearfield Counties, Pennsylvania.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2008 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

We use a variety of financial and operational measurements at interim periods to analyze our performance. These measurements include an analysis of production and sales revenue for the period; EBITDAX, a non-GAAP financial measurement; lease operating expenses per barrel of oil equivalent (“LOE per BOE”); and general and administrative (“G&A”) expenses as a percentage of operating revenue.

Results of Continuing Operations

	For the Three Months Ending June 30,				For the Six Months Ended June 30,
	2009		2008		2009		2008
Production:
Oil (Bbls)		183,695		189,551		364,878		377,908
Natural Gas (Mcf)		314,777		270,037		621,408		513,588
Total (BOE)a		236,158		234,557		468,446		463,506
Average daily production:
Oil (Bbls)		2,019		2,083		2,016		2,076
Natural Gas (Mcf)		3,459		2,967		3,433		2,822
Total (BOE)a		2,595		2,578		2,588		2,547
Average sales price:
Oil (per Bbl)	$	56.12	$	120.40	$	48.04	$	106.71
Natural Gas (per Mcf)	$	3.83	$	11.31	$	4.48	$	10.06
Total (per BOE)a	$	48.76	$	110.31	$	43.36	$	98.14
Average NYMEX pricesb:
Oil (per Bbl)	$	59.83	$	124.26	$	51.51	$	110.97
Natural Gas (per Mcf)	$	3.80	$	11.47	$	4.14	$	10.10

^a Natural gas is converted at the rate of six Mcf to one BOE and oil is converted at a rate of one Bbl to one BOE.

^b Based upon the average of bid week prompt month prices.

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	Production and Revenue by Basin
	For Three Months Ended June 30,						For Six Months Ended June 30,
	2009			2008			2009			2008
Appalachian
Revenues – Natural Gas	$	1,206,003		$	3,053,208		$	2,783,788		$	5,164,815
Volumes (Mcf)		314,777			270,037			621,408			513,588
Average Price	$	3.83		$	11.31		$	4.48		$	10.06
Illinois
Revenues – Oil	$	10,309,742		$	22,821,047		$	17,530,186		$	40,324,858
Volumes (Bbl)		183,695			189,551			364,878			377,908
Average Price	$	56.12		$	120.40		$	48.04		$	106.71
	Other Performance Measurements From Continuing Operations
	For Three Months Ended June 30,						For Six Months Ended June 30,
	2009			2008			2009			2008
EBITDAX $ (in Thousands)	$	4,091		$	8,323		$	12,790		$	15,710
LOE per BOE $	$	22.17		$	28.27		$	22.18		$	27.57
G&A as a Percentage of Operating Revenue(a)		33.6	%		21.6	%		26.9	%		20.7	%

(a) Includes realized derivatives during the period, which are recorded as Other Income (Expense).

General Overview

Operating revenue for the three and six month periods ended June 30, 2009 decreased 55.4% and 55.5%, respectively, when compared to the same periods in 2008. These decreases are primarily due to lower oil and gas prices when compared to 2008. The average sales price per BOE during the three and six month periods ended June 30, 2009 was $48.76 and $43.36, respectively, as compared to $110.31 and $98.14 during the comparable periods of 2008. Partially offsetting the decrease in commodity prices was an increase in total production. Total production for the three and six month periods ended June 30, 2009 increased approximately 0.7% and 1.1%, respectively, when compared to the same periods in 2008.

Operating expenses decreased $0.7 million, or 4.0%, for the second quarter of 2009 as compared to the same period in 2008 and increased $1.5 million, or 5.0%, for the first six months of 2009 as compared to the same period in 2008. Operating expenses are primarily comprised of: production expenses; general and administrative expenses (“G&A”); exploration expenses; gains and losses on the disposal of assets; impairment expense; and depreciation, depletion, amortization, and accretion (“DD&A”) expenses. The decrease in operating expenses during the three months ended June 30, 2009 can be primarily attributable to lower production and lease operating expenses and a decrease in exploration expenses, which is due to the reimbursement of certain costs pursuant to the PEA with Williams (See Note 2 to our consolidated financial statements). These reductions in operating expenses were partially offset by increases in G&A expense and DD&A. The increase in G&A is attributable to higher wages and benefits due to increased employee headcount when compared to the prior year. The increase in our DD&A expenses can be primarily explained by the downward revision in the estimated lives of our proved reserves at December 31, 2008. We calculate our depletion on a units-of-production basis, which accelerated in relation to our lower proved reserves base. The increase in operating expenses for the first six months of 2009 as compared to the same period in 2008 was primarily due to the increase in DD&A expense, which was partially offset by reductions in production and lease operating expenses.

EBITDAX, is used as a financial measure by us and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:

• Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial structure;

• The financial performance of our assets and valuation of the entity, without regard to financing methods, capital structure or historical costs basis;

• Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

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• The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX decreased approximately $4.2 million to $4.1 million for the three-month period ended June 30, 2009 as compared to the same period in 2008. The decrease in EBITDAX can be primarily attributed to lower commodity prices and increased G&A expenses, partially offset by lower production and lease operating expenses. EBITDAX decreased approximately $2.9 million to $12.8 million for the six-month period ended June 30, 2009 as compared to the same period in 2008. The decrease in EBITDAX can be primarily attributed to lower commodity prices and increased G&A expenses, partially offset by lower production and lease operating expenses as well as the early settlement of certain oil derivatives relating to 2011.

LOE per BOE measures the average cost of extracting oil and natural gas from our basin reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one barrel of oil equivalent from our oil and natural gas reserves in the ground. LOE per BOE decreased by $6.10 for the three months ended June 30, 2009 as compared to the same period in 2008 and $5.39 for the six months ended June 30, 2009 as compared to the same period in 2008. The expenses decreased as a result of several cost reduction measures implemented during the fourth quarter of 2008.

G&A expenses as a percentage of operating revenue, which includes realized derivatives, measures overhead costs associated with our management and operations. G&A expenses as a percentage of revenue increased to approximately 33.6% for the three-month period ended June 30, 2009, as compared to 21.6% for the same period in 2008. G&A expenses increased as a percentage of revenue to approximately 26.9% for the six-month period ended June 30, 2009, as compared to 20.7% for the same period in 2008. The increase in G&A expenses as a percentage of revenue was primarily due to a decrease in operating revenue, which was a function of lower commodity prices and an increase in the number of employees as compared to the prior year. A significant portion of the increase in G&A expenses can also be attributed to increased legal expenses relating to the PEA signed with Williams and the legal expenses associated with our Marcellus Shale leasing activities in the Commonwealth of Pennsylvania.

Comparison of the Three Months Ended June 30, 2009 to the Three Months Ended June 30, 2008.

Oil and gas revenue for the three month periods ended June 30, 2009 and 2008 ($ in thousands, except price per BOE) is summarized in the following table:

	For Three Months Ended June 30,
	2009		2008			Change			%
Oil and Gas Revenues:
Oil sales revenue	$	10,310	$	22,821		$	(12,511	)	(54.8	)%
Oil derivatives realized(a)		720		(7,417	)		8,137		109.7	%
Total oil revenue and derivatives realized	$	11,030	$	15,404		$	(4,374	)	(28.4	)%
Gas sales revenue	$	1,206	$	3,053		$	(1,847	)	(60.5	)%
Gas derivatives realized(a)		824		(366	)		1,190		325.1	%
Total gas revenue and derivatives realized	$	2,030	$	2,687		$	(657	)	(24.5	)%
Consolidated sales	$	11,516	$	25,874		$	(14,358	)	(55.5	)%
Consolidated derivatives realized(a)		1,544		(7,783	)		9,327		119.8	%
Total oil and gas revenue and derivatives realized	$	13,060	$	18,091		$	(5,031	)	(27.8	)%
Total BOE Production		236,158		234,557			1,601		0.7	%
Average Realized Price per BOE	$	55.30	$	77.13		$	(21.83	)	(28.3	)%

^(a) Realized derivatives are included in Other Income (Expense) on the Consolidated Statements of Operations

Average realized price received for oil and gas during the second quarter of 2009 was $55.30 per BOE, a decrease of 28.3%, or $21.83 per BOE, from the same quarter in 2008. The average price for oil, after the effect of derivative activities, decreased 26.1%, or $21.22 per barrel, to $60.05 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 35.2%, or $3.50 per Mcf, to $6.45 per Mcf. Our derivative activities effectively increased net realized price by $6.54 per BOE in the second quarter of 2009 and decreased net realized prices by $33.18 per BOE in the second quarter of 2008.

Production volumes in the second quarter of 2009 increased 0.7% from the second quarter of 2008 . Natural gas production increased approximately 16.6%, primarily due to the success of our drilling operations in the Butler County, Pennsylvania region of the Appalachian Basin. This increase was partially offset by significant pipeline curtailment affecting our operations in Westmoreland County, Pennsylvania. Oil production decreased approximately 3.1% in the second quarter of 2009 as compared to the same period in 2008, primarily due to decreased development and activity levels thus far in 2009. Overall, our production for the three months ending June 30, 2009 averaged 2,595 BOE per day, of which 77.8% was attributable to oil and 22.2% to natural gas.

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Other operating revenues for the three months ended June 30, 2009 and June 30, 2008 were approximately $25,000 and $31,000, respectively. We generate other operating revenue from various activities such as revenue from the transportation of third-party natural gas in the Appalachian Basin.

Production and lease operating expenses decreased approximately $1.4 million, or 21.0%, in the second quarter of 2009 from the same period in 2008. These expenses have decreased year-over-year primarily due to decreased activity levels, primarily in the Illinois Basin, and several cost reduction measures implemented during the fourth quarter of 2008 to mitigate discretionary spending and to lower overall operating expenses.

G&Aexpenses for the second quarter of 2009 increased approximately $475,000, or 12.1%, to $4.4 million from the same period in 2008. These expenses have increased year-over-year primarily due legal, wages and benefits expenses. Legal expenses have increased due to accruals associated with the pending actions related to our Marcellus Shale leasing activities (see Note 11 to our consolidated financial statements) and due to expenses incurred in relation to the PEA signed with Williams (see Note 2 to our consolidated financial statements). Wages and benefits have increased primarily as a result of an increase in the number of employees throughout 2008.

Gain (loss) on disposal of assets for the three months ended June 30, 2009 was approximately a gain of $28,000 as compared to a loss of $194,000 for the same period in 2008. We, from time to time, sell or dispose of property and equipment in the normal course of business and recognize a gain or loss based on the price received for those assets compared to the book carrying value at the time of sale or disposal.

Exploration expense of oil and gas properties for the second quarter of 2009 decreased approximately $1.2 million from an expense of $982,000 for the same period in 2008. This decrease is primarily due to reimbursement of seismic acquisition and processing costs, incurred during 2009, as a part of the PEA signed with Williams during the second quarter of 2009 (see Note 2 to our consolidated financial statements).

DD&A expenses for the three months ended June 30, 2009 increased approximately $1.7 million, or 24.9%, from $4.9 million for the same period in 2008. This increase is primarily attributable to the decrease in our proved reserves as of December 31, 2008. We calculate our depletion on a units-of-production basis, which accelerated in relation to our lower proved reserves base. Also contributing to the increase was the amortization of undeveloped acreage during the second quarter of 2009, which totaled $419,000 compared to $0 in the second quarter of 2008.

Interest expense, net of interest income, for the three months ended June 30, 2009 was approximately $378,000 as compared to $123,000 for the same period in 2008. The increase of $255,000 was primarily due to the decrease in the amount of cash on hand, for which we receive interest income, as well as depressed interest rates when compared to last year. Also contributing to the increase was a higher average balance of long-term debt, lines of credit, and other loans and notes payable.

Loss on Derivatives, net includes a loss of approximately $10.5 million for the second quarter of 2009 as compared to a loss of $73.6 million for the same period in 2008. These changes were attributable to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other income (expense) was income of approximately $13,000 in the second quarter of 2009 as compared to income of approximately $14,000 for the same period in 2008. Our other income and expense is characterized by the recognition of gains or losses on the sale of scrap inventory and physical yard inventory adjustments and fluctuates from period to period.

Net income tax benefit decreased by approximately $20.2 million in the three months ended June 30, 2009 to $5.8 million as compared to $26.1 million for the same period in 2008. The decrease was primarily due to the decrease in the loss from continuing operations before taxes which was primarily attributable to a reduction in the losses incurred on derivatives.

Net loss from continuing operations after income taxes for the three months ended June 30, 2009 was $9.4 million as compared to a net loss of $38.4 million for the same period in 2008, a decrease of approximately $29.0 million. The decrease was caused by our unrealized losses on derivatives, which were significantly lower during the second quarter of 2009 than the same period in 2008 and can be attributed to a decrease in oil and gas prices.

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Comparison of the Six Months Ended June 30, 2009 to the Six Months Ended June 30, 2008.

Oil and gas revenue for the six month periods ended June 30, 2009 and 2008 ($ in thousands, except price per BOE) is summarized in the following table:

	For Six Months Ended June 30,
	2009		2008			Change			%
Oil and Gas Revenues:
Oil sales revenue	$	17,530	$	40,325		$	(22,795	)	(56.5	)%
Oil derivatives realized(a)(b)		3,983		(10,691	)		14,674		137.3	%
Total oil revenue and derivatives realized	$	21,513	$	29,634		$	(8,121	)	(27.4	)%
Gas sales revenue	$	2,784	$	5,165		$	(2,381	)	(46.1	)%
Gas derivatives realized(a)		1,333		(374	)		1,707		456.4	%
Total gas revenue and derivatives realized	$	4,117	$	4,791		$	(674	)	(14.1	)%
Consolidated sales	$	20,314	$	45,490		$	(25,176	)	(55.3	)%
Consolidated derivatives realized(a)		5,316		(11,065	)		16,381		148.0	%
Total oil and gas revenue and derivatives realized	$	25,630	$	34,425		$	(8,795	)	(25.5	)%
Total BOE Production		468,446		463,506			4,940		1.1	%
Average Realized Price per BOE	$	54.71	$	74.27		$	(19.56	)	(26.3	)%

^(a) Realized derivatives are included in Other Income (Expense) on the Consolidated Statements of Operations.

^(b) Excludes approximately $4.6 million in proceeds that were received upon the early settlement of oil hedges relating to the 2011 calendar year.

Average realized price received for oil and gas during the first six months of 2009 was $54.71 per BOE, a decrease of 26.3%, or $19.56 per BOE, from the same period in 2008. The average price for oil, after the effect of derivative activities, decreased 24.8%, or $19.46 per barrel, to $58.96 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 29.0%, or $2.70 per Mcf, to $6.63 per Mcf. Our derivative activities effectively increased net realized price by $11.35 per BOE in the first half of 2009 and decreased net realized prices by $23.87 per BOE in the first half of 2008.

Production volumes in the first six months of 2009 increased 1.1% from the first six months of 2008. Natural gas production increased approximately 21.0%, primarily due to the success of our drilling operations in the Butler County, Pennsylvania region of the Appalachian Basin. This increase was partially offset by significant pipeline curtailment affecting our operations in Westmoreland County, Pennsylvania. Oil production decreased approximately 3.4% in the first six months of 2009 as compared to the same period in 2008, primarily due to decreased development and activity levels thus far in 2009. Overall, our production for the six months ending June 30, 2009 averaged 2,588 BOE per day, of which 77.9% was attributable to oil and 22.1% to natural gas

Other operating revenues for the six months ended June 30, 2009 and June 30, 2008 were approximately $57,000 and $63,000, respectively. We generate other operating revenue from various activities such as revenue from the transportation of third-party natural gas in the Appalachian Basin.

Production and lease operating expenses decreased approximately $2.4 million, or 18.7%, in the six month period ended June 30, 2009 from the same period in 2008. These expenses have decreased year-over-year primarily due to decreased activity levels, primarily in the Illinois Basin, and several cost reduction measures implemented during the fourth quarter of 2008 to mitigate discretionary spending and to lower overall operating expenses.

G&Aexpenses for the first six months of 2009 increased approximately $1.0 million, or 14.3%, to $8.1 million from the same period in 2008. These expenses have increased year-over-year primarily due legal, wages and benefits expenses. Legal expenses have increased due to accruals associated with the pending actions related to our prior Marcellus Shale leasing projects (see Note 11 to our consolidated financial statements) and due to expenses incurred in relation to the PEA signed with Williams (see Note 2 to our consolidated financial statements). Wages and benefits increased primarily due to the increase in total employees when compared to the prior year.

Gain (loss) on sale assets for the six months ended June 30, 2009 was a loss of $400,000 as compared to a loss of $151,000 for the same period in 2008. The loss recognized during the first half of 2009 was primarily due to the sale of our Southwest Region assets in Texas and New Mexico.

Exploration expense of oil and gas properties for the first six months of 2009 decreased approximately $446,000 from expense of $1.3 million for the same period in 2008. This decrease is primarily due to reimbursement of seismic acquisition and processing costs, incurred during 2009, as a part of the PEA signed with Williams during the second quarter of 2009 (see Note 2 to our consolidated financial statements).

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DD&A expenses for the six months ended June 30, 2009 increased approximately $3.1 million, or 32.1%, from $9.7 million for the same period in 2008. This increase is primarily attributable to the decrease in our proved reserves as of December 31, 2008. We calculate our depletion on a units-of-production basis, which accelerated in relation to our lower proved reserves base. Also contributing to the increase was the amortization of undeveloped acreage during the second quarter of 2009, which totaled $419,000 compared to $0 in the second quarter of 2008.

Interest expense, net of interest income, for the six months ended June 30, 2009 was approximately $772,000 as compared to $552,000 for the same period in 2008. This increase is primarily attributable to the lower average balance of cash on hand during 2009, for which we receive interest income, as well as depressed interest rates when compared to last year. During the second quarter of 2008 we paid off all of our outstanding long-term debt with a portion of the proceeds from our public offering of common stock.

Loss on derivatives, net includes a loss of approximately $4.9 million for the first half of 2009 as compared to a loss of $89.9 million for the same period in 2008. These changes were attributable to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the end of the last period while gains would suggest the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market. In addition, we recognized a gain of approximately $4.6 million during the first six months of 2009 due to the early settlement of oil hedges that related to 2011 production.

Other income (expense) was an expense of approximately $32,000 in the first half of 2009 as compared to income of approximately $19,000 for the same period in 2008. Our other income and expense is characterized by the recognition of gains or losses on the sale of scrap inventory and physical yard inventory adjustments and fluctuates from period to period.

Net income tax benefit decreased by approximately $23.6 million in the first six months of 2009 to $7.0 million as compared to $30.7 million for the same period in 2008. The decrease was primarily due to the decrease in the loss from continuing operations before taxes which was attributable to a reduction in the losses incurred on derivatives.

Net loss from continuing operations after income taxes for the six months ended June 30, 2009 was $10.8 million as compared to a net loss of $45.2 million for the same period in 2008, a decrease of approximately $34.4 million. The decrease was primarily caused by our unrealized losses on derivatives, which were significantly lower during the first six months of 2009 than the same period in 2008 and can be attributed to a decrease in oil and gas prices.

Capital Resources and Liquidity

Our primary needs for cash are for exploration, development and acquisition of oil and gas properties. During the six months ended June 30, 2009, $31.5 million of capital was expended on drilling projects, facilities and related equipment and acquisitions of unproved acreage. The capital program was funded by net cash flow from operations, proceeds from borrowings, and with proceeds from the sale of our Southwest Region assets. The 2009 capital budget of $48.6 million is expected to continue to be funded primarily by cash flow from operations and from borrowings under our Senior Credit Facility. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a significant continuation of depressed oil and gas prices or reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may also elect to issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Financial Condition and Cash Flows for the Six Months Ended June 30, 2009 and 2008

The following table summarizes our sources and uses of funds for the periods noted:

	Six Months Ended June 30, ($ in Thousands)
	2009			2008
Cash flows provided by operations	$	6,391		$	16,816
Cash flows used in investing activities		(11,023	)		(64,451	)
Cash flows provided by financing activities		—			86,391
Net increase (decrease) in cash and cash equivalents	$	(4,632	)	$	38,756

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Net cash provided by operating activities decreased by approximately $10.4 million in the first six months of 2009 over the same period in 2008. The decrease in 2009 was affected by a combination of factors, but primarily due to decreased commodity prices; partially offset by decreased lease operating expenses and an increase in realized gains from derivatives. Average prices decreased from $110.97 per BOE in the first six months of 2008 to $51.51 per BOE in the first six months of 2009.

Net cash used in investing activities decreased by approximately $53.4 million, or 82.9%, from the first six months of 2008 to $11.0 million in the first six months of 2009. This change was primarily the result of the proceeds received from the sale of our Southwest Region assets as well as a decrease in oil and gas property development activities.

Net cash provided by financing activities decreased by approximately $86.4 million from the first six months of 2008 to the first six months of 2009. The decrease is due to the issuance of common stock during the second quarter of 2008, from which we received net proceeds of approximately $113.1 million.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases or decreases, there could be a corresponding increase or decrease in the operating cost that we are required to bear for operations, as well as an increase or decrease in revenues.

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended June 30, 2009, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2008. We discuss critical recently adopted and issued accounting standards in Item 1. Financial Statements—Note 4,“Recently Issued Accounting Pronouncements.”

Non-GAAP Financial Measures

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring our performance, nor should it be used as an exclusive measure of cash flow, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. In addition, because we use capital assets, depreciation and amortization are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net incomes determined under GAAP and EBITDAX to evaluate our performance.

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The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented ($ in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net Loss From Continuing Operations	$	(9,437	)	$	(38,387	)	$	(10,784	)	$	(45,198	)
Add Back Depletion, Depreciation, Amortization and Accretion		6,581			4,879			12,752			9,651
Add Back Non-Cash Compensation Expense		621			736			1,096			1,104
Add Back Interest Expense		379			299			774			735
Add Back (Less) Exploration Expenses		(247	)		982			835			1,281
Less Interest Income		(1	)		(176	)		(2	)		(183	)
Add Back (Less) Loss (Gain) on Disposal of Assets		(28	)		194			400			151
Add Back Loss from Financial Derivatives		12,064			65,857			14,764			78,856
Less Income Tax Benefit		(5,841	)		(26,061	)		(7,045	)		(30,687	)
EBITDAX From Continuing Operations	$	4,091		$	8,323		$	12,790		$	15,710
Add EBITDAX From Discontinued Operations		—			1,410			53			2,690
EBITDAX	$	4,091		$	9,733		$	12,843		$	18,400

Volatility of Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas. We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps and costless collars in order to establish some price floor protection.

For the three and six month periods ended June 30, 2009, the net realized gain on oil and natural gas derivatives were approximately $1.5 million and $9.9 million, respectively, as compared to net realized losses of approximately $7.8 million and $11.1 million, respectively, for the comparable periods in 2008. Included in the net realized gain in the six months ended June 30, 2009 are cash settlements of approximately $4.6 million which resulted from the early settlement of certain oil hedges related to production in 2011. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

For the three and six month periods ended June 30, 2009, the net unrealized loss on oil and natural gas derivatives was $12.1 million and $14.8 million, respectively, as compared to losses of $65.9 million and $78.9 million , respectively, for the comparable periods in 2008. The net unrealized losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our derivatives transactions with two counterparties and have a netting agreement in place with each of these counterparties. While we do not obtain collateral to support the agreements, we do monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our current oil and natural gas derivative positions at June 30, 2009 refer to Note 7 of our Consolidated Financial Statements,“Fair Value of Financial Instruments and Derivative Instruments”.

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

We are exposed to various risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decline significantly, revenues and cash flow would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. We have designed our hedging policy to reduce the risk of price volatility for our production in the natural gas and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps and collars. The volume of derivative instruments that we may use is governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production and provides only partial price protection against

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declines in oil and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. See also the discussion above under “Item 2. — Volatility of Oil and Natural Gas Prices.”

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

Item 4. Controls And Procedures.

Based on management’s evaluation (with the participation of our Chief Executive Officer and Chief Financial Officer), as of the end of the period covered by this report, our CEO and CFO have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”)) are effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

The information contained in Part I, Item 1, Note 11,“Commitments and Contingencies—Litigation and Legal Proceedings” in this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item 1A. Risk Factors.

During the quarter ended June 30, 2009, there were no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

Item 4. Submission of Matters to a Vote of Security Holders.

On May 7, 2009, we held our 2009 Annual Meeting of Stockholders. Stockholders were asked to vote on the election of five directors to serve on our Board of Directors until the 2010 Annual Meeting of Stockholders and to ratify the appointment of Malin, Bergquist & Company, LLP as our independent registered public accounting firm for 2009. Our stockholders re-elected Lance T. Shaner, Benjamin W. Hulburt, Daniel J. Churay, John W. Higbee and John A. Lombardi as directors and ratified the appointment of Malin, Bergquist & Company, LLP.

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Item 6. Exhibits.

Exhibit Number	Exhibit Title
3.1**	Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.2**	Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.3**	Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
10.1**	Third Amendment to Credit Agreement, effective April 20, 2009, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on April 27, 2009).
10.2**	Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).
10.3**	Tax Partnership Agreement by and among Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).
10.4**	Limited Liability Company Agreement of RW Gathering, LLC effective as of June 18, 2009 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).
31.1*	Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2*	Certification of Chief Financial Officer (Principal Financial and Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1*	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.

* Filed herewith.

** Incorporated by reference hereto.

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SIGNATURES

Pursuant to the requirements 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.

	REX ENERGY CORPORATION
	(Registrant)
Date: August 3, 2009	By:	/s/ Benjamin W. Hulburt
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: August 3, 2009	By:	/s/ Thomas C. Stabley
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibit Number	Exhibit Title
3.1**	Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.2**	Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.3**	Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
10.1**	Third Amendment to Credit Agreement, effective April 20, 2009, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on April 27, 2009).
10.2**	Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).
10.3**	Tax Partnership Agreement by and among Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).
10.4**	Limited Liability Company Agreement of RW Gathering, LLC effective as of June 18, 2009 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).
31.1*	Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2*	Certification of Chief Financial Officer (Principal Financial and Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1*	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.

* Filed herewith.

** Incorporated by reference hereto.

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