Rex Energy 10-Q 2008 Q3 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 September 30, 2008

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 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

36,569,712 common shares were outstanding on November 7, 2008.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD SEPTEMBER 30, 2008

INDEX

		PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements.	4
	Consolidated Balance Sheets As of September 30, 2008 (Unaudited) and December 31, 2007	4
	Consolidated and Combined Statements of Operations (Unaudited) For the three and nine month periods ended September 30, 2008 and September 30, 2007	5
	Consolidated Statement of Changes in Owners’ Equity (Unaudited) For the nine month period ended September 30, 2008	6
	Consolidated and Combined Statements of Cash Flows (Unaudited) For the nine month periods ended September 30, 2008 and September 30, 2007	7
	Notes to Consolidated and Combined Financial Statements (Unaudited)	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	19
Item 3.	Quantitative and Qualitative Disclosure About Market Risk.	25
Item 4T.	Controls and Procedures.	26
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings.	27
Item 1A.	Risk Factors	27
Item 6.	Exhibits	28
SIGNATURES		29
EXHIBIT INDEX		30

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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:

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

• uncertainties about the estimates of 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 and the time frame within which they will be drilled;

• the timing and extent of changes in commodity prices for crude oil and natural gas;

• domestic demand for oil and natural gas;

• 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 our prospectus dated April 30, 2008 filed with the Securities and Exchange Commission on April 30, 2008.

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)

	September 30, 2008 (unaudited)			December 31, 2007 (audited)
ASSETS
Current Assets
Cash and Cash Equivalents	$	25,666		$	1,085
Accounts Receivable		9,795			8,805
Short-Term Derivative Instruments		43			20
Deferred Taxes		7,300			4,700
Inventory, Prepaid Expenses and Other		1,683			1,388
Total Current Assets		44,487			15,998
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		200,800			171,095
Unevaluated Oil and Gas Properties		62,819			31,834
Other Property and Equipment		18,595			4,397
Wells and Facilities in Progress		20,380			10,457
Pipelines		1,824			2,193
Total Property and Equipment		304,418			219,976
Less: Accumulated Depreciation, Depletion and Amortization		(41,432	)		(28,805	)
Net Property and Equipment		262,986			191,171
Assets Held for Sale		27,464			26,361
Intangible Assets and Other Assets – Net		1,779			2,034
Long-Term Derivative Instruments		2,119			—
Goodwill		32,700			32,700
Total Assets	$	371,535		$	268,264
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	10,150		$	7,152
Accrued Expenses		5,691			2,662
Short-Term Derivative Instruments		19,408			10,893
Current Portion of Long-Term Debt		—			29
Total Current Liabilities		35,249			20,736
Senior Secured Line of Credit and Long-Term Debt		—			27,207
Long-Term Derivative Instruments		24,375			18,843
Deferred Taxes		27,220			30,300
Other Deposits and Liabilities		7,275			345
Liabilities Related to Assets Held for Sale		1,148			1,099
Future Abandonment Cost		5,648			5,297
Total Liabilities	$	100,915		$	103,827
Commitments and Contingencies (See Notes)
Owners’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 36,569,712 shares issued and outstanding on September 30, 2008 and 30,794,712 shares issued and outstanding on December 31, 2007.		37			31
Additional Paid-In Capital		289,602			175,170
Retained Deficit		(19,019	)		(10,640	)
Other Comprehensive Loss		—			(124	)
Total Owners’ Equity		270,620			164,437
Total Liabilities and Owners’ Equity	$	371,535		$	268,264

See accompanying notes

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REX ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENT OF OPERATIONS

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

	Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated and Combined Predecessor Companies			Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated and Combined Predecessor Companies
	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2008			2007			2008			2007
OPERATING REVENUE
Oil and Natural Gas Sales	$	25,275		$	14,831		$	70,765		$	39,412
Other Revenue		29			26			93			77
Realized Loss on Derivatives		(6,640	)		(1,593	)		(17,704	)		(1,975	)
TOTAL OPERATING REVENUE		18,664			13,264			53,154			37,514
OPERATING EXPENSES
Production and Lease Operating Expenses		7,637			5,315			20,416			16,920
General and Administrative Expense		3,759			1,556			10,882			4,847
Accretion Expense on Asset Retirement Obligation		285			125			561			343
Exploration Expense of Oil and Gas Properties		1,113			—			2,395			—
Depreciation, Depletion, and Amortization		4,425			5,160			13,800			11,909
TOTAL OPERATING EXPENSES		17,219			12,156			48,054			34,019
INCOME FROM OPERATIONS		1,445			1,108			5,100			3,495
OTHER INCOME (EXPENSE)
Interest Income		137			2			320			3
Interest Expense		(291	)		(935	)		(1,026	)		(5,285	)
Gain (Loss) on Disposal of Assets		(6,274	)		3			(6,426	)		22
Unrealized Gain (Loss) on Derivatives		66,744			(2,361	)		(12,112	)		(9,095	)
Other Income (Expense)		(79	)		88			(61	)		(21	)
TOTAL OTHER INCOME (EXPENSE)		60,237			(3,203	)		(19,305	)		(14,376	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE MINORITY INTEREST AND INCOME TAXES		61,682			(2,095	)		(14,205	)		(10,881	)
MINORITY INTEREST SHARE OF LOSS		—			878			—			6,152
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		61,682			(1,217	)		(14,205	)		(4,729	)
Income Tax Benefit (Expense)		(24,899	)		143			5,789			143
INCOME (LOSS) FROM CONTINUING OPERATIONS		36,783			(1,074	)		(8,416	)		(4,586	)
Income (Loss) From Discontinued Operations, Net of Income Taxes		(28	)		264			37			(1,054	)
NET INCOME (LOSS)	$	36,755		$	(810	)	$	(8,379	)	$	(5,640	)
Earnings per common share:
Basic – income (loss) from continuing operations	$	1.01		$	(0.03	)	$	(0.25	)	$	(0.15	)
Basic – income (loss) from discontinued operations		0.00			0.01			0.00			(0.03	)
Basic – net income (loss)	$	1.01		$	(0.02	)	$	(0.25	)	$	(0.18	)
Basic – Weighted average shares of common stock outstanding		36,570			30,795			33,914			30,795
Diluted – income (loss) from continuing operations	$	1.00		$	(0.03	)	$	(0.25	)	$	(0.15	)
Diluted – income (loss) from discontinued operations		0.00			0.01			0.00			(0.03	)
Diluted – net income (loss)	$	1.00		$	(0.02	)	$	(0.25	)	$	(0.18	)
Diluted – Weighted average shares of common stock outstanding		36,784			30,795			33,914			30,795

See accompanying notes

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN OWNERS’ EQUITY

FOR THE NINE MONTH PERIOD ENDED SEPTEMBER 30, 2008

(Unaudited, $ in thousands)

	Common Stock			Additional Paid In Capital		Retained (Deficit) Earnings			Other Comprehensive Income (Loss)			Total Owners’ Equity
	Shares	Par Value
BALANCE December 31, 2007	30,794,712	$	31	$	175,170	$	(10,640	)	$	(124	)	$	164,437
Issuance of common stock, net of issuance costs of $544,000	5,775,000		6		112,986		—			—			112,992
Reclassification of unrealized loss on interest rate swap to Income Statement	—		—		—		—			124			124
Non-cash compensation expense	—		—		1,446		—			—			1,446
NET LOSS FROM CONTINUING OPERATIONS	—		—		—		(8,416	)		—			(8,416	)
NET INCOME FROM DISCONTINUED OPERATIONS	—		—		—		37			—			37
BALANCE September 30, 2008	36,569,712	$	37	$	289,602	$	(19,019	)	$	—		$	270,620

See accompanying notes

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REX ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENT OF CASH FLOWS

(Unaudited, $ in thousands)

	For the Nine months Ended September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss)	$	(8,379	)	$	(5,640	)
Adjustments to Reconcile Net (Loss) to Net Cash
Provided by Operating Activities
Minority Interest Share of (Loss)		—			(6,152	)
Non-cash Expense		1,692			—
Depreciation, Depletion and Amortization		15,319			13,454
Unrealized Loss on Derivatives		12,112			9,095
Deferred Income Tax (Benefit)		(5,763	)		—
Exploration Expense (Excluding G&G Expenses)		2,176			1,704
Accretion Expense on Asset Retirement Obligation		642			408
(Gain) Loss on Sale of Oil and Gas Properties		6,467			(192	)
Cash Flows from Operating Activities Due to
(Increase) in Accounts Receivable		(957	)		(463	)
(Increase) in Inventory, Prepaid Expenses and Other Assets		(295	)		(160	)
Increase (Decrease) in Accounts Payable and Accrued Expenses		4,264			(1,384	)
Net Changes in Other Assets and Liabilities		(502	)		879
NET CASH PROVIDED BY OPERATING ACTIVITIES		26,776			11,549
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		8,826			239
Acquisitions of Evaluated and Unevaluated Oil & Gas Properties		(41,241	)		(5,738	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(56,113	)		(20,167	)
NET CASH USED IN INVESTING ACTIVITIES		(88,528	)		(25,666	)
CASH FLOWS FROM FINANCING ACTIVITIES
(Repayments) of Long-Term Debts and Lines of Credit		(41,296	)		(103,415	)
Proceeds from Long-Term Debts and Lines of Credit		14,000			36,584
(Repayments) of Loans and Other Notes Payable		—			(901	)
Proceeds of Loans and Other Notes Payable		—			84
Proceeds from Lease Incentives		636			—
Net (Repayments) to Related Parties		—			(1,000	)
(Repayment) of Participation Liability		—			(2,141	)
Debt Issuance Costs		—			(1,180	)
Proceeds from the Issuance of Common Stock		113,537			96,800
Offering Costs		(544	)		(8,910	)
Capital Contributions by the Partners of the Predecessor Companies		—			300
Cash Distributions to the Partners of the Predecessor Companies		—			(2,112	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		86,333			14,109
NET INCREASE (DECREASE) IN CASH		24,581			(8	)
CASH – BEGINNING		1,085			600
CASH – ENDING	$	25,666		$	592
SUPPLEMENTAL DISCLOSURES
Cash Paid for Income Taxes		—			—
Interest Paid		1,019			5,659
NON-CASH ACTIVITIES
Redemption-Baseline Property Distribution		—			7,970
Conversion of Loan Payable to Capital		—			820
Acquisitions of Oil & Gas Properties		7,970			—
Step-Up of Asset Basis Resulting from the Acquisition of Minority Interests		—			71,876
Recordation of Goodwill		—			31,800

See accompanying notes

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REX ENERGY CORPORATION AND PREDECESSOR COMPANIES

NOTES TO THE CONSOLIDATED AND COMBINED 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, the Appalachian Basin and the Southwestern Region of the United States. We have pursued a balanced growth strategy of exploiting our sizeable inventory of lower risk developmental drilling locations, pursuing our higher potential exploration drilling prospects and actively seeking 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.

We refer to certain companies—Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New Albany-Indiana, LLC, PennTex Resources, L.P., PennTex Resources Illinois, Inc., Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy III LLC, Rex Energy IV, LLC, Rex Energy II Alpha Limited Partnership, Rex Energy Operating Corp. and Rex Energy Royalties Limited Partnership—collectively as the “Predecessor Companies.” We refer to each of the Predecessor Companies individually as:

Douglas Oil & Gas Limited Partnership	“Douglas Oil & Gas”
Douglas Westmoreland Limited Partnership	“Douglas Westmoreland”
Rex Energy Royalties Limited Partnership	“Rex Royalties”
Midland Exploration Limited Partnership	“Midland”
New Albany-Indiana, LLC	“New Albany”
PennTex Resources Illinois, Inc.	“PennTex Illinois”
PennTex Resources, L.P.	“PennTex Resources”
Rex Energy Limited Partnership	“Rex I”
Rex Energy II Limited Partnership	“Rex II”
Rex Energy II Alpha Limited Partnership	“Rex II Alpha”
Rex Energy III LLC	“Rex III”
Rex Energy IV, LLC	“Rex IV”
Rex Energy Operating Corp.	“Rex Operating”

Simultaneously with the consummation of our initial public offering of common stock, through a series of mergers and reorganization transactions, which we refer to as the “Reorganization Transactions,” Rex Energy Corporation acquired all of the outstanding equity interests of the Predecessor Companies. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and subsidiaries together with the Predecessor Companies, after giving effect to the Reorganization Transactions.

The interim consolidated financial statements of Rex Energy Corporation and combined financial statements of the Predecessor Companies 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 and combined 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 filed with the SEC on March 31, 2008.

The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include: (1) subsequent to the reorganization as described below, the consolidated accounts of Rex Energy Corporation and (2) prior to the reorganization the Predecessor Companies, the combined accounts of the Predecessor Companies under the common ownership of Lance T. Shaner. The consolidated and combined financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have a significant influence, but not control, are accounted for using the equity method of accounting, are carried at our share of net assets and are included in other assets on the balance sheet. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in other revenue on our consolidated statement of operations. All material intercompany balances and transactions have been eliminated.

The combined financial statements of the Predecessor Companies reflect the assets, liabilities, revenues, expenses and cash flows on a gross basis, and the economic interests not owned by Lance T. Shaner which are reflected as minority interests. All of the Predecessor Companies were under the common control of Lance T. Shaner, our Chairman, through his direct and indirect ownership interests and other contractual arrangements, as well as under the common management of Rex Operating.

On July 30, 2007, we reorganized by acquiring all of the outstanding equity interests of each of the Predecessor Companies through a series of mergers and reorganization transactions (the “Reorganization Transactions”). The Reorganization Transactions occurred simultaneously with the consummation of our initial public offering of common stock. The Reorganization Transactions were accounted for partially as an exchange of entities under common control for the interests in the Predecessor Companies which were contributed by Lance T. Shaner, and partially as an acquisition of minority interests using the purchase method of accounting for all the predecessor owners other than Lance T. Shaner pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations (“SFAS No. 141”).

Our initial public offering of shares of common stock consisted of 8,800,000 shares of common stock offered and sold by us at an offering price of $11.00 per share. We received gross proceeds from the offering of $96.8 million and incurred approximately $9.0 million in underwriting discounts, commissions and offering costs associated with the offering.

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The Reorganization Transactions resulted in our recognition of the acquisition of minority ownership interests and an associated increase in the book basis of certain property assets. These assets are subject to depletion and amortization expenses. The reorganization also resulted in our becoming subject to federal and state income taxes. Tax expenses had previously passed through to the equity owners of the Predecessor Companies and were not recorded on the books of the Predecessor Companies.

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 million 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 4.0 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 $6.7 million, were approximately $113.0 million.

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 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. During the three-month period ended September 30, 2008, we made no material acquisitions.

During the third quarter of 2008, we sold approximately 79,000 net undeveloped acres in Indiana and certain related non-producing wells, which was a part of our New Albany Shale exploration projects, for approximately $8.4 million in proceeds. A related loss of approximately $6.3 million was recorded as a part of continuing operations on our consolidated statement of operations.

3. FUTURE ABANDONMENT COST

We account for future abandonment costs using SFAS No. 143,“Asset Retirement Obligations” (“SFAS No. 143”). 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 No. 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.

	September 30, 2008			September 30, 2007
	($ in Thousands)			($ in Thousands)
Beginning Balance	$	6,396		$	5,269
Asset Retirement Obligation Incurred		186			492
Asset Retirement Obligation Settled		(313	)		(10	)
Asset Retirement Obligation Cancelled or Sold Well Properties		(116	)		—
Asset Retirement Obligation Accretion Expense		642			408
Total Asset Retirement Obligation	$	6,795		$	6,159

4. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In December 2007, the FASB issued SFAS No. 141(R),“Business Combinations.” SFAS No. 141(R) replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The statement will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009. We are in the process of evaluating the impact of SFAS No. 141(R) on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements”(“SFAS 160”), which provides direction on reporting minority (noncontrolling) interests in the consolidated financial statements. The standards set forth in SFAS No. 160 include clearly identifying and labeling noncontrolling interests in the consolidated statement of equity, separate from the parent’s equity; clearly identifying consolidated net income of the parent and the noncontrolling interests on the consolidated statement of income; consistently accounting for changes in the parent ownership interest when the parent preserves its controlling interest; any retained noncontrolling equity investment of a deconsolidated subsidiary and any resulting gain or loss will be measured using fair value and; disclosures must provide a level of detail that clearly identifies and separates the interests of the parent and the interest of the noncontrolling owners. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. We are currently evaluating the effect that the implementation of SFAS 160 will have on our results of operations and financial condition, but do not expect it will have a material impact.

In March 2008, the FASB issued SFAS No. 161,“Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.” SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are in the process of evaluating the impact of SFAS No. 161 on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162,“The Hierarchy of Generally Accepted Accounting Principles.” SFAS 162 sets forth identification of sources for accounting principles and the structure for decision making when selecting the principles to be employed during the preparation of financial statements, for entities in non-governmental industries, that are presented in alignment with United States generally accepted accounting principles (GAAP). SFAS 162 will be effective 60 days after the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411. We adopted SFAS No. 162 effective July 1, 2008 and the adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows.

5. CONCENTRATIONS OF CREDIT RISK

At times during the three-month period ended September 30, 2008, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $100,000. 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.

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6. LONG-TERM DEBT

On September 28, 2007, we entered into a senior credit facility with KeyBank National Association (“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”). Our borrowing base was $90 million at September 30, 2008; however, the Senior Credit Facility provides that the revolving credit facility may be increased up to $200 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 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) the London Interbank Offered Rate for one, two, three, six or nine months (“Adjusted Libor Rate”) 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 Rate 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 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 provide the lenders a reserve report evaluating our oil and gas properties as of the immediately preceding January 1 and July 1. A 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, once per calendar year, each elect 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 Credit Agreement (the “First Amendment”). The First Amendment provides that the borrowing base under the Senior Credit Facility is increased from $75 million to $90 million effective April 14, 2008. The increased borrowing base will remain in effect until the next borrowing base re-determination date. The First Amendment also amends 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 amends the Senior Credit Facility with respect to our ability to enter into commodity and swap agreements. The First Amendment provides 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 amends 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 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.

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.

At September 30, 2008, we did not have any borrowing under the Senior Credit Facility and had $90 million available for future borrowings under the facility.

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 consists of the following at September 30, 2008 and December 31, 2007:

	September 30, 2008		December 31, 2007
	($ in thousands)		($ in thousands)
Senior Credit Facility1	$	—	$	27,186
Other Loans and Notes Payable		—		50
Total Debts		—		27,236
Less Current Portion of Long-Term Debt		—		(29	)
Total Long-Term Debts	$	—	$	27,207

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

Financial instruments include cash and cash equivalents, receivables, payables, commodity and interest rate derivatives. The carrying value of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value of our long-term debt instruments approximates the fair value as the debt facilities carry a market rate of interest.

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The fair value of the net liability associated with our derivative instruments was approximately $41,621,000 and $29,716,000 at September 30, 2008 and December 31, 2007, respectively.

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 entered into oil and natural gas commodity derivative instruments. As of September 30, 2008 and December 31, 2007, 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 (a “put”) and ceiling price (a “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 sell oil and natural gas in the normal course of business and utilize derivative commodity instruments to minimize the variability in forecasted cash flows due to price movements in oil and natural gas sales.

We incurred net payments of $6,640,000 and $17,704,000 during the three and nine-month periods ended September 30, 2008, respectively, as compared to net payments of $1,593,000 and $1,975,000 for the comparable periods in 2007. These net payments and receipts are included in operating revenue on our consolidated and combined statement of operations. Unrealized gains and losses associated with these commodity derivative instruments are included in other income (expense) and amounted to a gain of $66,792,000 and a loss of $11,756,000 for the three and nine-month periods ended September 30, 2008, respectively, as compared to losses of $2,361,000 and $9,095,000 for the comparable periods in 2007.

Our open financial commodity derivative instrument positions at September 30, 2008 consisted of:

Period	Contract Type	Volume	Average Derivative Price
Oil
2008	Swaps	51,000 Bbls	$65.58
2008	Collars	105,000 Bbls	$65.46 – 84.00
2009	Swaps	192,000 Bbls	$64.00
2009	Collars	410,000 Bbls	$64.16 – 73.73
2010	Swaps	180,000 Bbls	$62.20
2010	Collars	408,000 Bbls	$62.94 – 86.85
2011	Collars	444,000 Bbls	$81.08 – 157.41
	Total	1,790,000 Bbls
Natural gas
2008	Collars	240,000 Mcf	$7.00 – 9.26
2009	Collars	840,000 Mcf	$7.14 – 9.29
2010	Collars	840,000 Mcf	$7.79 – 11.11
2011	Collars	720,000 Mcf	$8.00 – 14.75
	Total	2,640,000 Mcf

As of September 30, 2008, we had entered into an interest rate swap derivative instrument which hedged our interest rate risk associated with changes in LIBOR on $20,000,000 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 September 30, 2008, was a liability of $356,000, an increase of $149,000 since December 31, 2007, 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 $356,000 unrealized loss for the nine months ended September 30, 2008 as a decrease to Unrealized Gain (Loss) on Derivatives on our Consolidated and Combined Statement of Operations.

The combined fair value of derivatives included in our consolidated balance sheets as of September 30, 2008 and December 31, 2007 is summarized in the table below. Derivative activities are conducted with major financial and commodities trading institutions which we believe are acceptable credit risks. We do not obtain any form of collateral from the counterparties. At times, such risks may be concentrated with certain counterparties. We have master netting agreements with our counterparties and the credit worthiness of our counterparties is subject to periodic review.

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	September 30, 2008			December 31, 2007
	($ in thousands)
Derivative assets:
Natural gas
– collars	$	686		$	20
– swaps		—			—
Crude oil
– collars		1,476			—
– swaps		—			—
Total derivative assets	$	2,162		$	20
Derivative liabilities:
Interest rate swaps		(356	)		(207	)
Natural gas
– collars		(200	)		(349	)
– swaps		—			—
Crude oil
– collars		(26,446	)		(15,515	)
– swaps		(16,781	)		(13,665	)
Total derivative liabilities	$	(43,783	)	$	(29,736	)

Adoption of SFAS No. 157

Effective January 1, 2008, we adopted SFAS No. 157, which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in SFAS No. 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 No. 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 No. 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 September 30, 2008, 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 No. 157 ($ in thousands):

	Total Carrying Value as of September 30, 2008			Fair Value Measurements at September 30, 2008 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	$	(41,264	)	$	—	$	(41,264	)	$	—
– interest rate swaps	$	(356	)	$	—	$	(356	)	$	—

8. INCOME TAXES

We account for income taxes in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109,“Accounting for Income Taxes.” This statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in its financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax rates. We recognized deferred tax assets and liabilities upon the consummation of the Reorganization Transactions and acquisition of minority interests. Before these events, the Predecessor Companies were pass-through entities that did not pay income taxes and did not reflect deferred tax assets and liabilities.

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Effective August 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109“ (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109,“Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We also adopted FASB Staff Position No. FIN 48-1, “ Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”) 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 48-1 had no effect on our financial position or results of operations.

The Predecessor Companies were treated as partnerships or subchapter S corporations for federal and state income tax purposes. Accordingly, income taxes were not reflected in the combined financial statements because the resulting profit or loss was included in the income tax returns of the individual stockholders, members or partners. Accordingly, we did not derecognize any tax benefits, nor recognize any interest expense or penalties on unrecognized tax benefits as of the date of adoption. Income tax expense has been provided for on our consolidated statement of operations prospectively for periods after August 1, 2007.

We filed a consolidated U.S. federal income tax return and separate or consolidated state income tax 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. Our practice is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties as of September 30, 2008.

Our deferred tax assets at September 30, 2008 include an estimated net operating loss carry forward of $12.1 million, with the expiration period beginning in 2028 and full expiration occurring in 2029, for tax losses recognized since the effective date of the Reorganization Transactions. Income tax benefit for the nine month period ended September 30, 2008 is comprised of the following:

	Nine-Month Period Ended September 30, 2008
	($ in thousands)
Current:
Federal	$	—
State		—
Deferred:
Federal		5,054
State		710
Total Income Tax Benefit	$	5,764

A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows:

	Nine-Month Period Ended September 30, 2008
	($ in Thousands)
Net loss before income taxes	$	14,143
Statutory income tax rate		35	%
Tax benefit recognized using statutory U.S. income tax rate		4,950
Change in estimated future state rate		666
Permanent and other changes		(562	)
Tax benefit recognized using statutory U.S. income tax rate		5,054
State income tax benefit		710
Income tax benefit	$	5,764
Effective income tax rate		40.8	%

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Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax liabilities/(assets) are comprised of the following at September 30, 2008 and December 31, 2007:

	September 30, 2008			December 31, 2007
	($ in thousands)
Tax effects of temporary differences for:
Current:
Assets:
Unrealized loss on derivatives	$	6,820		$	4,350
Other		480			350
Total current deferred tax assets		7,300			4,700
Long-Term:
Assets:
Asset Retirement Obligation		2,670			2,580
Unrealized loss on derivatives		10,360			7,580
Net Operating Loss Carry forward		4,730			1,830
Other		(6,710	)		1,110
Total long-term deferred tax assets		11,050			13,100
Liabilities:
Book basis of oil and gas properties in excess of tax basis		(38,270	)		(43,400	)
Net long-term deferred tax liability	$	(27,220	)	$	(30,300	)

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 September 30, 2008 and December 31, 2007, we had 36,569,712 and 30,794,712 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 $6.7 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 continue to use the remaining net proceeds to fund, in part, our remaining capital expenditure program for 2008, which includes our ASP project and our leasing and drilling activities in the Marcellus Shale. 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 contributions to the plan are discretionary. Our contributions to the plan were approximately $69,000 and $46,000 for the three-month periods ended September 30, 2008 and 2007 and $198,000 and $149,000 for the nine-month periods ended September 30, 2008 and 2007, respectively.

2007 Long-Term Incentive Plan

We have granted stock option, 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. 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, will 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 a five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively. The blended forfeiture rate in effect at September 30, 2008 is 9.4%.

Stock Options

During the nine-month period ended September 30, 2008, the Compensation Committee awarded grants of 499,200 nonqualified stock options to twenty-one employees and four non-employee directors. The nonqualified stock options granted to our employees 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 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 also provide that all unvested options vest and become immediately exercisable upon a change in control of the Company, as such term is defined in the Plan.

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Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. All of the stock options granted under the Plan expire five or ten years from the date they are granted. 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

Stock Appreciation Rights

During the nine-month period ended September 30, 2008, the Compensation Committee awarded 109,500 stock appreciation rights (“SARs”) to five employees. 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 strike price. The SARs have an exercise price equal to $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 the Company, as such term is defined in the Plan. The outstanding SARs issued as of September 30, 2008 may only be exercised for cash settlement.

Information with respect to these stock option activities is summarized below:

Stock Options

	Number of Options Granted	Options Forfeited or Cancelled	Outstanding				Exercisable
Exercise Prices			Options Outstanding	Weighted- Average Remaining Contractual Life (Years)	Weighted- Average Exercise Price		Options	Weighted Average Exercise Price
$16.24	17,000		17,000	4.93	$	16.24
$21.10	30,000		30,000	4.90	$	21.10
$19.92	38,000		38,000	4.87	$	19.92
$21.68	15,000		15,000	4.81	$	21.68
$23.28	10,000		10,000	4.78	$	23.28
$27.05	100,000	—	100,000	4.69	$	27.05	—	—
$23.88	75,000	—	75,000	4.64	$	23.88	—	—
$23.83	5,500	—	5,500	4.63	$	23.83	—	—
$23.00	75,000	—	75,000	9.59	$	23.00	—	—
$22.34	70,000	—	70,000	9.54	$	22.34	—	—
$13.56	63,700	—	63,700	9.39	$	13.56	—	—
$9.99	675,000	140,000	535,000	9.10	$	9.99	—	—
$9.50	150,000	25,000	125,000	9.10	$	9.50	—	—
Total	1,324,200	165,000	1,159,200	8.08	$	15.13	—	—

SARs

	Number of SARs Granted	SARs Forfeited or Cancelled	Outstanding				Exercisable
Exercise Prices			SARs Outstanding	Weighted- Average Remaining Contractual Life (Years)	Weighted- Average Exercise Price		SARs	Weighted Average Exercise Price
$13.56	109,500	36,000	73,500	9.38	$	13.56	—	—
Total	109,500	36,000	73,500	9.38	$	13.56	—	—

The value of each stock option grant on the date of grant is estimated by using the Black-Scholes option pricing model. SARs are re-valued each month using Black-Scholes option pricing model. During the nine-month period ended September 30, 2008, 499,200 stock options and 109,500 SARs were granted for which the following average valuation and assumptions were used: average fair value of stock options $8.38; average expected dividend per share of $0.00; average expected historical volatility factor of 45%; average risk-free interest rate of 3.04%, and an average expected lives of 4 to 6.5 years. Our expected historical volatility factor was determined by assessing the common stock trading history of 8 publicly-traded oil and gas companies that we determined to be similar to us in ways such as their operating strategy, capital structure, production mix and volume and asset size. The risk-free interest rate was determined by interpolating the average yield on a U.S. Treasury bond for a period approximately equal to the expected average life of the options. The average expected life has been determined using the “simplified method” as referenced in SEC Staff Accounting Bulletin 107 (“SAB 107”) and SEC Staff Accounting Bulletin 110 (“SAB 110”) in which the average expected life of the option or SAR is equal to the average of the term of the option and the vesting period. We elected to use the simplified method for determining the average expected life because we do not have a history on which to base estimates for the term to exercise of our granted stock options and SARs.

Restricted Stock Awards

During the nine-month period ended September 30, 2008, the Compensation Committee issued 20,000 shares of restricted common stock to one employee, with all restrictions on transfer associated with such shares scheduled to terminate in May 2013. 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 are determined by the Compensation Committee on an individual award basis. The restrictions on the stock lapse immediately upon a change in control of the Company, 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 September 30, 2008, total unrecognized compensation cost related to the restricted common stock grant was $423,000.

We estimate to report compensation expense of approximately $7.3 million related to our stock options, SARs, and RSAs over their remaining vesting periods. Unless sooner terminated, our outstanding options and SARs as of September 30, 2008 will all be fully-vested by September 2011. There were no options or SARs exercised, proceeds received or associated income tax benefits realized during the nine-month period ended September 30, 2008.

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11. COMMITMENTS AND CONTINGENCIES

Legal Reserves

At September 30, 2008, our Consolidated Balance Sheet included approximately $327,000 in reserve for the legal costs and expenses associated with the putative class action lawsuit filed against PennTex Illinois and Rex Operating in the United States District Court for the Southern District of Illinois. At December 31, 2007, our Consolidated Balance Sheet included $384,000 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 September 30, 2008, we had three drilling commitments in our Appalachian Basin. The first commitment requires us to drill two natural gas wells each year for the next five years, beginning in 2008. We estimate an average investment in each well to be $1.9 million for a total five year drilling commitment of $19.0 million. 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, by September 2009 at an estimated cost of $1.9 million.

Leasing

At September 30, 2008, we had three installment payment commitments on mineral 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 $2,002,700, in 2012. The second commitment requires that we pay $250 per mineral acre for 5,761 acres, or $1,440,250, in each of the next four years for a total commitment of $5,761,000. The third commitment requires that we pay $350 per mineral acre for 762 acres, or $266,700, in each of the next four years for a total commitment of $1,066,800. These amounts have been recorded on the balance sheet as Other Deposits and Liabilities.

Environmental

Due to the nature of the natural gas and oil 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 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 H₂S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.

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. 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 Combined 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 September 30, 2008, we have posted $1,008,000 in various letters of credit to secure our drilling and related operations.

Lease Commitments

At September 30, 2008, we have lease commitments for three different office locations. Rent expense has been recorded in general and administrative expense for continued operations as $173,000 and $90,000 and as $18,000 and $17,000 for discontinued operations for the nine-month periods ended 2008 and 2007, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands).

2008 – From Continuing Operations	$	112
2008 – From Discontinued Operations		6
2009		450
2010		452
2011		454
2012		456
Thereafter		479
Total	$	2,409

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Litigation and Legal Proceedings

On June 27, 2008, the United States District Court for the Southern District of Texas, Houston Division, issued a Memorandum and Order confirming the commercial arbitration award of the arbitration panel conveyed by the American Arbitration Association in Houston, Texas in the commercial arbitration proceeding commenced on June 21, 2006 by PennTex Resources and Lance T. Shaner against ERG Illinois Holdings, Inc. (“ERG Holdings”) and Scott Y. Wood (“Wood”). The August 20, 2007 commercial arbitration award required, among other matters, that Wood provide PennTex Resources with a signed release or dismissal of his individual claims filed against Tsar Energy II, LLC and Richard A. Cheatham in the 334th Judicial District Court of Harris County, Texas (the “Tsar Case”). In addition, the commercial arbitration award required Wood to pay PennTex Resources a total of $141,003 (after deducting amounts payable by PennTex Resources to Wood relating to Wood’s legal fees and expenses incurred in the Tsar Case) and required ERG Holdings to pay PennTex Resources a total of $165,835. In its Memorandum and Order, the United States District Court granted PennTex Resource’s motion to confirm the commercial arbitration award and denied Wood’s motion to vacate the award, granted PennTex Resource’s request to offset monetary judgments of the opposing parties set forth in the award, and denied PennTex Resource’s motion for sanctions against Wood’s attorney. 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 decision compelling Wood to participate in the arbitration proceeding and its order confirming the arbitration award. ERG Holdings did not join in Wood’s appeal and a judgment was entered against ERG Holdings in favor PennTex Resources. 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. We intend to vigorously oppose Wood in his appeal and we believe that the likelihood of an unfavorable outcome of this matter is remote.

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 and $322,000 and are included in Other Liabilities at September 30, 2008 and December 31, 2007, respectively.

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12. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

On September 3, 2008, our Board of Directors authorized management to pursue the sale of our Southwest Region assets. In accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, we have reclassified these assets and associated liabilities as held for sale on our balance sheet and have reported the results of these operations under discontinued operations on our consolidated statement of operations. The recording of DD&A expense related to our Southwest Region assets ceased on September 3, 2008.

We evaluated the value, less cost to sell, of our Southwest Region assets, as of September 30, 2008, and determined that the fair market value exceeded the carrying amount; therefore no adjustment to the carrying value was required. We have included $27.5 million and $26.4 million of net assets classified as held for sale in the accompanying balance sheets as of September 30, 2008 and December 31, 2007, respectively, which represents the carrying value of the oil and gas properties of our Southwest Region assets. We have included $1.1 million and $1.1 million, respectively, of liabilities associated with the assets held for sale, which represents the future abandonment cost of those oil and gas properties. Additionally, we have reclassified the results of discontinued operations in our consolidated statement of operations as income of $37,000 and a loss of $1.1 million for the nine month period ended September 30, 2008 and September 30, 2007, respectively, and a loss of $28,000 for the three month period ended September 30, 2008 as compared to income of $264,000 for the same period in 2007. See Note 13.Subsequent Events for further information on our discontinued operations.

As of September 30, 2008, we have not recorded any gain or loss associated with the planned sale of these assets. 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.

	Three Months Ended September 30, ($ in thousands)					Nine Months Ended September 30, ($ in thousands)
	2008			2007		2008			2007
Revenues:
Oil and Gas Sales	$	1,934		$	1,760	$	6,041		$	3,869
Other Revenue		112			104		304			266
Total Operating Revenue		2,046			1,864		6,345			4,135
Costs and Expenses:
Production and Lease Operating Expense		631			594		1,769			1,413
General and Administrative Expense		207			235		680			558
Accretion Expense on Asset Retirement Obligation		4			29		81			65
Exploration Expense of Oil and Gas Properties		1,074			—		2,195			1,704
Depreciation, Depletion and Amortization		177			641		1,519			1,545
(Gain) Loss on Sale of Oil and Gas Properties		—			—		41			(173	)
Other (Income) Expense		—			3		(2	)		(21	)
Total Costs and Expenses		2,093			1,502		6,283			5,091
Income (Loss) from Discontinued Operations Before Income Taxes		(47	)		362		62			(956	)
Income Tax Expense (Benefit)		(19	)		98		25			98
Income (Loss) From Discontinued Operations, net of taxes	$	(28	)	$	264	$	37		$	(1,054	)
Production:
Crude Oil (Bbls)		11,085			15,395		34,452			33,256
Natural Gas (Mcf)		80,379			114,973		259,835			288,790
Total (BOE)		24,482			34,557		77,758			81,388

The consolidated statements of cash flows include the discontinued operations for the nine months ended September 30, 2008 and 2007. We use a centralized approach to the cash management, financing and hedging programs of our operations and, accordingly, debt and derivative liabilities were not allocated to these operations.

13. SUBSEQUENT EVENTS

Subsequent to the balance sheet date of September 30, 2008, management determined that due to declining commodity prices it was reasonably possible that our Southwestern Region assets would be sold at a price lower than originally anticipated when the sale process was initiated. In accordance with SFAS No. 144, a long-lived asset classified as held for sale must be measured at the lower of its carrying amount or fair value less cost to sell. Accordingly, in the fourth quarter of 2008, we may be required to reduce the carrying value of our Southwestern Region assets to the anticipated sale price, less the cost to sell.

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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, 2007 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

Our management uses 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 Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007
Production:
Oil (Bbls)		196,780		192,686		574,690		573,421
Natural gas (Mcf)		250,704		184,702		764,293		557,455
Total (BOE)a		238,564		223,470		702,072		666,330
Average daily production:
Oil (Bbls)		2,139		2,094		2,097		2,100
Natural gas (Mcf)		2,725		2,008		2,789		2,042
Total (BOE)a		2,593		2,429		2,562		2,441
Average sales prices:
Oil (per Bbl)	$	115.32	$	70.79	$	109.65	$	61.73
Natural gas (per Mcf)	$	10.30	$	6.45	$	10.14	$	7.20
Total (per BOE)a	$	105.95	$	66.51	$	100.79	$	59.15
Average NYMEX pricesb:
Oil (per Bbl)	$	118.52	$	75.38	$	113.48	$	66.19
Natural gas (per Mcf)	$	9.00	$	6.03	$	9.73	$	6.78

^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 September 30,						For Nine Months Ended September 30,
	2008			2007			2008			2007
Appalachian
Revenues – Natural Gas	$	2,582,720		$	1,191,948		$	7,747,630		$	4,014,531
Volumes (MCF)		250,704			184,702			764,293			557,455
Average Price	$	10.30		$	6.45		$	10.14		$	7.20
Illinois
Revenues – Oil	$	22,692,083		$	13,639,380		$	63,016,941		$	35,397,245
Volumes (BBL)		196,780			192,686			574,690			573,421
Average Price	$	115.32		$	70.79		$	109.65		$	61.73
	Other Performance Measurements From Continuing Operations
	For Three Months Ended September 30,						For Nine Months Ended September 30,
	2008			2007			2008			2007
EBITDAX $		7,653		$	6,481		$	23,362		$	15,726
LOE per BOE $		31.11		$	23.43		$	28.38		$	25.04
G&A as a Percentage of Operating Revenue		20.1	%		11.7	%		20.5	%		12.9	%

General Overview

Operating revenue increased 40.7% for the third quarter of 2008 over the same period in 2007. This increase is primarily due to higher production with higher average sales prices per BOE, partially offset by increased realized losses on derivative activity. For the third quarter of 2008, production increased 6.8% to 238,564 BOE over the same period in 2007 primarily due to the continued success of our drilling programs. Realized losses on derivative activities increased by $5.0 million from a loss of approximately $1.6 million in the third quarter of 2007.

Operating expenses increased $5.1 million, or 41.7%, for the third quarter of 2008 as compared to the same period in 2007. Operating expenses are primarily comprised of production expenses, general and administrative expenses, exploration expenses and depreciation, depletion, amortization, and accretion expenses. The increase in operating expenses was due, in part, to increased production expenses, G&A expenses, and exploration expenses. The increase in G&A expenses is primarily due to an increase in employee headcount as compared to the third quarter of 2007 as well as non-cash compensation expenses which were not present until the fourth quarter of 2007. Production expenses increased primarily due to cost escalations in steel, chemicals and electricity used to operate our oil and gas fields. Exploration expenses increased primarily due to expenses associated with reservoir characterization and geologic modeling.

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

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

EBITDAX increased approximately $1.2 million to $7.7 million for the three-month period ended September 30, 2008 as compared to the same period in 2007. The increase in EBITDAX can be primarily attributed to higher production and higher average commodity prices during the third quarter of 2008.

LOE per BOE measures the average cost of extracting oil and natural gas from our basin reserves during the period, excluding production taxes. 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 increased by $7.68 for the three months ended September 30, 2008 as compared to the same period in 2007. These expenses typically increase on a per barrel basis as we add new wells, particularly in our Illinois Basin, where lifting costs tend to be higher due to the secondary recovery method that is employed to extract oil from the reservoir. Also contributing to the higher production expenses were increased prices for goods and services used in the course of normal operations, such as the cost of steel, chemicals and electricity as well as certain non-recurring maintenance expenses relating to pit cleaning and road and repair work.

G&A expenses as a percentage of operating revenue measures overhead costs associated with our management and operations. G&A expenses as a percentage of revenue increased to approximately 20.1% for the three-month period ended September 30, 2008, as compared to 11.7% for the same period in 2007. The increase in G&A expenses as a percentage of revenue was primarily due to consulting fees related to Sarbanes-Oxley compliance and additional staffing needs at our corporate headquarters. Our employee headcount has also increased in the field offices in relation to our growth and in association with the Lawrence Field ASP project in the Illinois Basin and the Marcellus Shale project in the Appalachian Basin. A significant portion of the increase in G&A expenses can also be attributed to non-cash compensation expenses, which totaled approximately $464,000 for the third quarter of 2008 compared to $0 during the same period in 2007.

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Comparison of the Three Months Ended September 30, 2008 to the Three Months Ended September 30, 2007.

Oil and gas revenue for the three-month periods ended September 30, 2008 and 2007 ($ in thousands) is summarized in the following table:

	For Three Months Ended September 30,
	2008			2007			Change			%
Oil and Gas Revenues:
Oil sales revenue	$	22,692		$	13,640		$	9,052		66.4	%
Oil derivatives realized		(6,353	)		(1,888	)		(4,465	)	236.5	%
Total oil revenue	$	16,339		$	11,752		$	4,587		39.0	%
Gas sales revenue	$	2,583		$	1,191		$	1,392		116.9	%
Gas derivatives realized		(287	)		295			(582	)	(197.3	)%
Total gas revenue	$	2,296		$	1,486		$	810		54.5	%
Consolidated sales	$	25,275		$	14,831		$	10,444		70.4	%
Consolidated derivatives realized		(6,640	)		(1,593	)		(5,047	)	316.8	%
Total oil and gas revenue	$	18,635		$	13,238		$	5,397		40.8	%
Total BOE Production		238,564			223,470			15,094		6.8	%
Average Realized Price per BOE	$	77.97		$	59.36		$	18.61		31.4	%

Average realized price received for oil and gas during the third quarter of 2008 was $77.97 per BOE, an increase of 31.4%, or $18.61 per BOE, from the same quarter in 2007. The average price for oil, after the effect of derivative activities, increased 36.2%, or $22.05 per barrel, to $82.94 per barrel. The average price for natural gas, after the effect of derivative activities, increased 13.9%, or $1.11 per Mcf, to $9.15 per Mcf. Our derivative activities effectively decreased net realized price by $27.78 per BOE in the third quarter of 2008 and decreased net realized prices by $7.14 per BOE in the third quarter of 2007.

Production volumesin the third quarter of 2008 increased 6.8% from the third quarter of 2007 primarily due to the continued success of our drilling and development programs. Our production for the third quarter of 2008 averaged approximately 2,593 BOE per day of which 82.5% was attributable to the Illinois Basin and 17.5% to the Appalachian Basin.

Other operating revenue for the three months ended September 30, 2008 increased approximately $3,000 to $29,000 from $26,000 for the same period in 2007. 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 increased approximately $2.3 million or 43.7%, in the third quarter of 2008 from the same period in 2007. These expenses have increased year-over-year primarily due to the greater number of wells in service as compared to the third quarter of 2007 and the increasing cost of goods and services used to operate our oil and gas fields. Also contributing to the increase in expense were higher production taxes, which can be directly attributable to our increased production, sales prices, and subsequent revenues.

General and administrative expenses for the third quarter of 2008 increased approximately $2.2 million, or 141.5%, to $3.8 million from the same period in 2007. The increase in G&A expenses was primarily due to increased costs associated with consulting fees related to Sarbanes-Oxley compliance and additional staffing needs in our corporate headquarters. Our employee headcount has also increased in the field offices in relation to our growth. The recognition of non-cash compensation expenses (stock options) of $464,000 in the third quarter of 2008 also contributed to the increase in G&A expenses from the third quarter of 2007. We had not issued any stock options prior to the fourth quarter of 2007.

Exploration expense of oil and gas properties for the third quarter of 2008 increased approximately $1.1 million from expense of $0 for the same period in 2007. This increase is primarily due to expenses associated with reservoir characterization and geologic modeling.

Depreciation, depletion, amortization, and accretion(“DD&A”) expenses for the three months ended September 30, 2008 decreased approximately $735,000, or 14.2%, from $5.2 million for the same period in 2007. This decrease is primarily due to the amortization of loan costs during the third quarter of 2007, this amortization has significantly decreased due to the change in our outstanding debt.

Interest expense, net of interest income, for the three months ended September 30, 2008 was approximately $154,000 as compared to $933,000 for the same period in 2007. The decrease of $779,000 was primarily due to the decrease in the average balance of our long-term debt, lines of credit, and other loans and notes payable. All of our outstanding long-term debt was paid in full with a portion of the proceeds from our public offering of common stock which closed on May 5, 2008.

Gain (loss) on sale of oil and gas properties for the three months ended September 30, 2008 was approximately a loss of $6.3 million as compared to a gain of $3,000 for the same period in 2007. The loss recognized during the third quarter of 2008 was primarily due to the sale of our New Albany Shale acreage holdings in areas of the Illinois Basin.

Unrealized gain (loss) on oil and gas derivatives includes a gain of approximately $66.7 million for the third quarter of 2008 as compared to a loss of $2.4 million for the same period in 2007. 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. Unrealized losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract while unrealized 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.

Other income (expense) was approximately an expense of $79,000 in the third quarter of 2008 as compared to income of approximately $88,000 for the same period in 2007. This decrease was primarily due to the write-down of several items in our physical yard inventories

Net gain (loss) before minority interests and provision for income taxes for the three months ended September 30, 2008 was a gain of approximately $61.7 million as compared to a net loss of $2.1 million for the same period in 2007, an increase of approximately $63.8 million. The increase was caused by our unrealized gains on derivatives, which can be attributed to a decrease in oil and gas prices.

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Comparison of the Nine Months Ended September 30, 2008 to the Nine Months Ended September 30, 2007.

Oil and gas revenue for the nine-month periods ended September 30, 2008 and 2007 ($ in thousands) is summarized in the following table:

	For Nine Months Ended September 30,
	2008			2007			Change			%
Oil and Gas Revenues:
Oil Sales Revenue	$	63,017		$	35,397		$	27,620		78.0	%
Oil Derivatives Realized		(17,044	)		(2,467	)		(14,577	)	590.9	%
Total Oil Revenue	$	45,973		$	32,930		$	13,043		39.6	%
Gas Sales Revenue	$	7,748		$	4,015		$	3,733		93.0	%
Gas Derivatives Realized		(660	)		492			(1,152	)	(234.1	)%
Total Gas Revenue	$	7,088		$	4,507		$	2,581		57.3	%
Consolidated Sales	$	70,765		$	39,412		$	31,353		79.6	%
Consolidated Derivatives Realized		(17,704	)		(1,975	)		(15,729	)	796.4	%
Total Oil & Gas Revenue	$	53,061		$	37,437		$	15,624		41.7	%
Total BOE Production		702,072			666,336			35,736		5.4	%
Average Realized Price per BOE	$	75.59		$	56.21		$	19.37		34.5	%

Average realized price received for oil and gas during the nine months ended September 30, 2008 was $75.59 per BOE, an increase of 34.5%, or $19.37 per BOE, compared to the same period in the prior year. The average price for oil, after the effect of derivative activities, increased 39.1%, or $22.48 per barrel, to $79.95 per barrel. The average price for natural gas, after the effect of derivative activities, increased 14.7%, or $1.19 per Mcf, to $9.28 per Mcf. Our derivative activities effectively decreased net realized price by $25.22 per BOE in the first nine months of 2008 and decreased net realized prices by $2.97 per BOE in the first nine months of 2007.

Production volumesincreased 5.4% for the nine months ended September 30, 2008 from the same period in 2007 primarily due to the continued success of our drilling and development programs. Our production for the first nine months of 2008 averaged approximately 2,562 BOE per day of which 81.9% was attributable to the Illinois Basin and 18.1% to the Appalachian Basin.

Other operating revenue for the nine months ended September 30, 2008 increased approximately $16,000 to $93,000 from $77,000 for the same period in 2007. 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 increased approximately $3.5 million, or 20.7%, in the nine months ended September 30, 2008 from the same period in 2007. These expenses have increased year-over-year primarily due to the greater number of wells in service as compared to the first nine months of 2007 and the increasing cost of goods and services used to operate our oil and gas fields. Also contributing to the increase in expense were higher production taxes, which can be directly attributable to our increased production, sales price, and subsequent revenues.

General and administrative expenses for the nine months ended September 30, 2008 increased approximately $6.0 million, or 125%, to $10.9 million from the same period in 2007. The increase in G&A expenses was primarily due to increased costs associated with consulting fees related to Sarbanes-Oxley compliance and additional staffing needs in our corporate headquarters. The employee headcount has also increased in our field offices in relation to our growth. Also contributing to the increase in G&A expenses from the third quarter of 2007 is the recognition of non-cash compensation expenses (stock options) of $1.6 million, no stock options existed prior to the fourth quarter of 2007.

Depreciation, depletion, amortization, and accretion(“DD&A”) expenses for the nine months ended September 30, 2008 increased approximately $1.9 million, or 15.9%, from $11.9 million for the same period in 2007. The increase in DD&A expenses was primarily due to an increased asset base and increased production.

Exploration expense of oil and gas properties for the nine months ended September 30, 2008 increased to approximately $2.4 million from expense of $0 in the same period for 2007. The increase in expense is primarily due to expenses associated with reservoir characterization and geolgic modeling.

Interest expense, net of interest income, for the nine months ended September 30, 2008 was approximately $706,000 as compared to $5.3 million for the same period in 2007. The decrease of $4.6 million was primarily due to the decrease in the average balance of our long-term debt, lines of credit, and other loans and notes payable. All of our outstanding long-term debt was repaid in full with a portion of the proceeds from our public offering of common stock which closed on May 5, 2008.

(Loss) gain on sale of oil and gas properties for the nine months ended September 30, 2008 was a loss of approximately $6.4 million as compared to a gain of $22,000 for the same period in 2007. The loss during the first nine months of 2008 can be primarily attributed to the sale of our New Albany Shale acreage in areas of the Illinois Basin, which resulted in a loss of approximately $6.3 million.

Unrealized loss on oil and gas derivatives includes a loss of approximately $12.1 million for the nine months ended in 2008 as compared to a loss of $9.1 million for the same period in 2007. 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. Unrealized losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract while unrealized 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.

Other expensewas approximately $61,000 in the nine months ended September 30, 2008 as compared to $21,000 for the same period in 2007. This increase was primarily due to the recognition of the write down on various items held in our physical yard inventories.

Net loss before minority interests and provision for income taxes for the nine months ended September 30, 2008 was approximately $14.2 million as compared to $10.9 million for the same period in 2007, a decrease of approximately $3.3 million. The decrease was primarily caused by the loss on sale of our New Albany Shale assets and our unrealized losses on derivatives, which can be attributed to higher oil and gas prices. This was partially offset by higher income from operations. All of the minority interests were acquired as a part of the Reorganization Transactions on July 30, 2007.

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Capital Resources and Liquidity

Our primary needs for cash are for exploration, development and acquisition of oil and gas properties. During the first nine months of 2008, $97.4 million of capital was expended on drilling projects, facilities and related equipment and acquisitions of additional interests in producing properties and unproved acreage. The capital program was funded by net cash flow from operations and proceeds from a secondary equity offering during the second quarter of 2008. The 2008 capital budget of $138.7 million is expected to continue to be funded primarily by cash flow from operations, proceeds from borrowings, and with the proceeds of the equity offering completed in the second quarter of 2008. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a decrease in oil and gas prices or a 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 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 Nine Months Ended September 30, 2008 and 2007

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

	Nine Months Ended September 30, ($ in thousands)
	2008			2007
Cash flows provided by operations	$	26,776		$	11,549
Cash flows used in investing activities		(88,528	)		(25,666	)
Cash flows provided by financing activities		86,333			14,109
Net increase in cash and cash equivalents	$	24,581		$	(8	)

Net cash provided by operating activities increased by approximately $15.2 million in the first nine months of 2008 over the same period in 2007. The increase in 2008 was affected by a combination of factors including increased sales volumes and increased commodity prices; partially offset by increased production and lease operating expenses, increased G&A expenses and an increase in realized losses from derivatives. Average realized prices increased from $56.21 per BOE in the first nine months of 2007 to $75.59 per BOE in the first nine months of 2008. Our production volumes, from continuing operations, increased 5.4% to 702,072 BOE in the first nine months of 2008 from 666,336 BOE in the first nine months of 2007.

Net cash used in investing activities increased by approximately $62.9 million, or 245%, from the first nine months of 2007 to $88.5 million in the first nine months of 2008. This change was the result of an increase in capital spending on drilling and development activities as well as increased leasing efforts in the Commonwealth of Pennsylvania areas that we believe to be prospective for the Marcellus Shale.

Net cash provided by financing activities increased by approximately $72.2 million, or 512%, from the first nine months of 2007 to $86.3 million in the first nine months of 2008. The increase is primarily due to proceeds that were received as a result of our public offering of common stock during the second quarter of 2008 and a decrease in the repayments of long-term debt and lines of credit. These increases in cash were partially offset by lower proceeds received from long-term debt and lines of credit.

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 September 30, 2008, there were no material changes to the critical accounting policies previously reported by the Company in its Annual Report on Form 10-K for the year ended December 31, 2007. 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, to analyze such things as:

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

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

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

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

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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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Net Income (Loss) From Continuing Operations:	$	36,783		$	(1,074	)	$	(8,416	)	$	(4,586	)
Add Back Depletion, Depreciation & Amortization		4,425			5,160			13,800			11,909
Add Back Accretion Expense on Future Abandonment Obligations		285			125			561			343
Add Back Non-Cash Compensation Expense		464			—			1,567			—
Add Back Interest Expense		291			935			1,026			5,285
Add Back Exploration & Impairment Expenses		1,113			—			2,395			—
Less Interest Income		(137	)		(2	)		(320	)		(3	)
Add Back (Gain) Losses on Disposal of Assets		6,274			(3	)		6,426			(22	)
Add Back Unrealized (Gains) Losses from Financial Derivatives		(66,744	)		2,361			12,112			9,095
Add Back Minority Interest Share of Net (Loss)		—			(878	)		—			(6,152	)
Less Income Tax (Benefit)		24,899			(143	)		(5,789	)		(143	)
EBITDAX From Continuing Operations	$	7,653		$	6,481		$	23,362		$	15,726
Add EBITDAX From Discontinued Operations		1,208			1,032			3,898			2,185
EBITDAX	$	8,861		$	7,513		$	27,260		$	17,911

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-month period ended September 30, 2008, the net realized loss on oil and natural gas derivatives was approximately $6.6 million as compared to a net realized loss of approximately $1.6 million for the comparable period in 2007. For the nine month period ended September 30, 2008, the net realized loss on oil and natural gas derivatives was approximately $17.7 million as compared to a net realized loss of approximately $2.0 million for the comparable period in 2007. The losses are reported as net realized loss on derivatives in our Consolidated and Combined Statement of Operations.

For the three-month periods ended September 30, 2008 and 2007, the net unrealized gain (loss) on oil and natural gas derivatives was a gain of approximately $66.7 million and a loss of $2.4 million, respectively. For the nine-month periods ended September 30, 2008 and 2007, the net unrealized loss on oil and natural gas derivatives was approximately $12.1 million and $9.1 million, respectively. The net unrealized losses are reported as net unrealized losses on derivatives in our Consolidated and Combined Statement 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

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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 September 30, 2008 refer to Note 7 of our Consolidated and Combined 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 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.

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Item 4T. Controls And Procedures.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level.

During the quarter ended September 30, 2008, there were no changes in our internal control over financial reporting which materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We are not yet required to comply with the internal control reporting requirements mandated by Section 404 of the Sarbanes-Oxley Act of 2002 due to a transition period established by rules of the SEC for newly public companies. We will be required to comply with the internal control over financial reporting requirements for the first time, and will be required to provide a management report on internal control over financial reporting and an attestation report on internal controls from our independent registered public accounting firm, in connection with our Annual Report on Form 10-K for the year ending December 31, 2008. While we are not yet required to comply with the internal control reporting requirements mandated by Section 404 of the Sarbanes-Oxley Act of 2002 for this reporting period, we are preparing for future compliance with these requirements by strengthening, assessing and testing our system of internal controls to provide the basis for our report.

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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 September 30, 2008, 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, 2007.

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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**	Employment Agreement by and between William L. Ottaviani and Rex Energy Operating Corp. dated August 1, 2008 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2008).
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: November 7, 2008	By:	/s/ Benjamin W. Hulburt
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: November 7, 2008	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**	Employment Agreement by and between William L.Ottaviani and Rex Energy Operating Corp. dated August 1, 2008 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2008).
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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