Rex Energy 10-Q 2007 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, 2007

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	(I.R.S. employer
incorporation or organization)	identification number)

1975 Waddle Road

State College, Pennsylvania 16803

(Address of principal executive offices)

(Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

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 1932 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  ¨     No  x

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

Large Accelerated filer  ¨     Accelerated filer  ¨     Non-accelerated filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨     No  x

30,794,702 common shares were outstanding on November 14, 2007.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2007

INDEX

		PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
SPECIAL NOTE REGARDING THE REGISTRANT		2
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements.	3
	Consolidated and Combined Balance Sheets As of September 30, 2007 (Unaudited) and December 31, 2006	3
	Consolidated and Combined Statements of Operations (Unaudited) For the three and nine-month periods ended September 30, 2007 and September 30, 2006	4
	Consolidated and Combined Statement of Changes in Stockholders’ Equity (Deficit) (Unaudited) For the nine-month period ended September 30, 2007	5
	Consolidated and Combined Statement of Cash Flows (Unaudited) For the nine-month period ended September 30, 2007	6
	Notes to Consolidated and Combined Financial Statements (Unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	20
Item 3.	Quantitative and Qualitative Disclosure About Market Risk.	29
Item 4T.	Controls and Procedures.	30
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings.	30
Item 1A.	Risk Factors	30
Item 6.	Exhibits	30
SIGNATURES		32
EXHIBIT INDEX		33

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q may contain forward-looking statements. 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 July 24, 2007 filed with the Securities and Exchange Commission on July 26, 2007.

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.

SPECIAL NOTE REGARDING THE REGISTRANT

In this quarterly report, 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.” In this quarterly report, 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 the Company’s initial public offering of its 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 its subsidiaries, after giving effect to the Reorganization Transactions.

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Item 1. Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED AND COMBINED BALANCE SHEETS

($ in Thousands)

	Rex Energy Corporation Consolidated September 30, 2007 (unaudited)			Predecessor Companies Combined December 31, 2006 (audited)
ASSETS
Current Assets
Cash and Cash Equivalents	$	592		$	600
Related Party Receivable		—			2
Accounts Receivable		7,349			6,884
Short-Term Derivative Instruments		190			1,275
Deferred Taxes		3,045			—
Inventory, Prepaid Expenses and Other		1,680			1,520
Total Current Assets		12,856			10,281
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		194,755			127,370
Unevaluated Oil and Gas Properties		31,484			14,569
Other Property and Equipment		5,159			4,182
Wells in Progress		4,609			2,844
Pipelines		2,207			1,765
Total Property and Equipment		238,214			150,730
Less: Accumulated Depreciation, Depletion and Amortization		(29,444	)		(17,715	)
Net Property and Equipment		208,770			133,015
Other Assets – Net		807			1,172
Intangible Assets – Net		1,284			—
Long-Term Derivative Instruments		3			143
Goodwill		31,800			—
Total Assets	$	255,520		$	144,611
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses	$	8,403		$	8,336
Short-Term Derivative Instruments		5,450			2,978
Accrued Distributions		—			102
Current Lines of Credit		—			37,581
Current Portion of Long-Term Debt		29			2,867
Related Party Payable		—			1,820
Total Current Liabilities		13,882			53,684
Senior Secured Line of Credit and Long-Term Debt		18,186			44,961
Other Loans and Notes Payable—Long-Term Portion		28			481
Long-Term Derivative Instruments		7,097			1,698
Participation Liability		—			2,141
Deferred Taxes		34,800			—
Other Deposits and Liabilities		417			405
Future Abandonment Cost		6,159			5,269
Total Liabilities	$	80,569		$	108,639
Commitments and Contingencies (See Notes)
Minority Interests		—			36,589
Owners' Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 30,794,702 shares issued and outstanding on September 30, 2007		31			1
Additional Paid-In Capital		174,988			1,460
Retained Earnings		(68	)		(581	)
Partner’s and Member’s (Deficit)		—			(1,497	)
Total Owners’ Equity (Deficit)		174,951			(617	)
Total Liabilities, Minority Interests and Owners’ Equity (Deficit)	$	255,520		$	144,611

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 and Combined			Rex Energy Combined Predecessor Companies			Rex Energy Corporation Consolidated and Combined			Rex Energy Combined Predecessor Companies
	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
OPERATING REVENUE
Oil and Natural Gas Sales	$	16,591		$	11,175		$	43,281		$	30,155
Other Revenue		130			107			343			358
Realized Gain(Loss) on Derivatives		(1,593	)		(1,204	)		(1,975	)		(4,225	)
TOTAL OPERATING REVENUE		15,128			10,078			41,469			26,288
OPERATING EXPENSES
Production and Lease Operating Expenses		5,910			4,208			18,333			9,625
General and Administrative Expense		1,791			1,008			5,405			2,663
Accretion Expense on Asset Retirement Obligation		154			90			408			255
Exploration Expense of Oil and Gas Properties		—			—			1,704			—
Depreciation, Depletion, and Amortization		5,800			2,645			13,454			6,347
TOTAL OPERATING EXPENSES		13,655			7,951			39,305			18,890
INCOME FROM OPERATIONS		1,473			2,127			2,345			7,398
OTHER INCOME (EXPENSE)
Interest Income		2			4			3			80
Interest Expense		(935	)		(1,507	)		(5,285	)		(3,472	)
Gain on Sale of Oil and Gas Properties		3			—			195			91
Unrealized (Loss) Gain on Derivatives		(2,361	)		6,098			(9,095	)		5,524
Other Income (Expense)		85			(53	)		0			(220	)
TOTAL OTHER INCOME (EXPENSE)		(3,206	)		4,542			(14,181	)		2,003
NET INCOME (LOSS) BEFORE MINORITY INTEREST AND (PROVISION) BENEFIT FOR TAXES		(1,733	)		6,669			(11,837	)		9,401
MINORITY INTEREST SHARE OF (NET INCOME) LOSS		878			(2,542	)		6,152			(4,091	)
NET INCOME (LOSS) BEFORE INCOME TAX		(855	)		4,127			(5,685	)		5,310
Income Tax Benefit (Expense)		45			—			45			—
NET INCOME (LOSS)	$	(810	)	$	4,127		$	(5,640	)	$	5,310
Earnings per common share for the two month period ended September 30, 2007:
Net loss for the two month period ended September 30, 2007	$	(68	)		0		$	(68	)		0
Basic and fully diluted earnings per share	$	0.00					$	0.00
Weighted average shares of common stock outstanding		30,795						30,795

See accompanying notes

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN OWNERS’ EQUITY (DEFICIT) AND MINORITY INTERESTS

DECEMBER 31, 2006 THROUGH SEPTEMBER 30, 2007

(Unaudited, $ in Thousands)

	Common Stock			Additional Paid In Capital		Retained Earnings			Members’ Equity			Partners’ Equity			Total Owners’ Equity			Minority Interests
BALANCE December 31, 2006	$	1		$	1,460	$	(580	)	$	5,969		$	(7,467	)	$	(617	)	$	36,589
NET INCOME (LOSS) prior to reorganization							373			(4,002	)		(1,943	)		(5,572	)		(6,152	)
CAPITAL CONTRIBUTIONS prior to reorganization													820			820			300
DISTRIBUTIONS prior to reorganization													(294	)		(294	)		(1,830	)
REDEMPTION prior to reorganization																			(7,970	)
REORGANIZATION and acquisition of minority interests effected through the exchange of 21,994,702 shares of common stock for partnership interests and shares of Predecessor Companies to Rex Energy Corporation		(1	)		83,051		207			(1,967	)		8,884			90,174			(20,937	)
ISSUANCE of 8,800,000 shares of common stock		31			90,477											90,508			—
NET LOSS after reorganization							(68	)								(68	)		—
BALANCE September 30, 2007		31			174,988		(68	)		—			—			174,951			—

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,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income	$	(5,640	)	$	5,310
Adjustments to Reconcile Net Income (Loss) to Net Cash
Provided by Operating Activities
Minority Interest Share of (Loss) Income		(6,152	)		4,092
Depreciation, Depletion, and Amortization		13,454			6,346
Unrealized Loss (Gain) on Derivatives		9,095			(5,524	)
Exploration Expense		1,704			—
Accretion Expense on Asset Retirement Obligation		408			255
Plugging Costs Incurred		—			—
(Gain) on Sale of Oil and Gas Properties		(192	)		(91	)
Cash Flows from Operating Activities Due to
(Increase) Decrease in Accounts Receivable		(463	)		1,325
(Increase) Decrease in Inventory, Prepaid Expenses and Other Assets		(160	)		324
(Decrease) in Accounts Payable and Accrued Expenses		(1,384	)		(2,411	)
Net Changes in Other Assets and Liabilities		879			859
NET CASH PROVIDED BY OPERATING ACTIVITIES		11,549			10,485
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		239			91
Acquisitions of Oil & Gas Properties		(5,738	)		(46,707	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(20,167	)		(5,289	)
NET CASH USED IN INVESTING ACTIVITIES		(25,666	)		(51,905	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net (Repayments) Proceeds from Long-Term Debts and Lines of Credit		(67,224	)		36,987
Net (Repayments) Proceeds from Loans and Other Notes Payable		(424	)		659
Net (Repayments to) Related Parties		(1,000	)		(7,214	)
Repayment of Participation Liability		(2,141	)
Debt Issuance Costs		(1,180	)		(1,483	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		87,890
Capital Contributions by the Partners of the Predecessor Companies		300			19,664
Cash Distributions to the Partners of the Predecessor Companies		(2,112	)		(9,162	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		14,109			39,451
NET (DECREASE) INCREASE IN CASH		(8	)		(1,969	)
CASH – BEGINNING		600			2,688
CASH – ENDING	$	592		$	719
SUPPLEMENTAL DISCLOSURES
Cash Paid for Income Taxes	$	0.00		$	0.00
Interest Paid	$	5,659		$	2,772
NON-CASH ACTIVITIES
Redemption-Baseline Property Distribution	$	7,970
Conversion of Loan Payable to Capital	$	820
Repayment of Loan Payable via Transfer of New Albany Interests				$	1,715
Accrued Distribution				$	29
Conversion of Deposit on Leasehold Acreage to Leasehold Acquisition				$	3,500
NON-CASH ACTIVITIES RELATED TO THE REORGANIZATION:
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

FOR THE THREE AND NINE MONTH PERIODS ENDED SEPTEMBER 30, 2007 AND 2006

Rex Energy Corporation is an independent oil and gas company operating in the Illinois Basin, the Appalachian Basin and the southwestern region of the United States. We pursue 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.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Reporting

The interim consolidated financial statements of Rex Energy Corporation (the “Company”) 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, the Company’s ability to obtain additional capital, and the success of oil and natural gas recovery techniques. You should read these interim financial statements in conjunction with the audited combined financial statements and notes thereto included in the Company’s prospectus dated July 24, 2007 filed with the Securities and Exchange Commission on July 26, 2007.

Certain prior year amounts have been reclassified to conform to the current year presentation. The March 31, 2007 Combined Statement of Operations and Cash Flow Statement lines titled “Impairment of Oil and Gas Properties” has been modified to “Exploration Expense of Oil and Gas Properties” to more accurately reflect the nature of these expenditures. Unrealized Loss(Gain) on Derivatives has been reclassified from Operating Revenue to Other Income (Expense) to be more consistent with income statement presentations of such items common to the oil and natural gas exploration industry.

Prior to the Reorganization Transactions (as defined below), the Company referred to the combined entities as the “Founding Companies”. With the completion of the Reorganization Transactions, those entities are subsequently referred to herein as the “Predecessor Companies”.

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 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 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 Energy Operating Corp. All material intercompany balances and transactions have been eliminated.

On July 30, 2007, the Company reorganized by the acquisition of 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 the Company’s initial public offering of its common stock. The Reorganization Transactions were accounted for as an exchange of entities under common control for the interests in the Predecessor Companies which were contributed by Lance T. Shaner, and 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”)

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The initial public offering of shares of common stock consisted of 8,800,000 shares of common stock offered and sold by the Company and 800,000 offered and sold by selling stockholders of the Company. The Company received total net proceeds of approximately $89.2 million from this offering. The Company did not receive any proceeds from the shares of common stock sold by the selling shareholders. The net proceeds from the offering were used to repay in full all of the senior debt facilities and other notes payable of the Predecessor Companies, except for borrowings under the Rex IV revolving credit agreement. On July 24, 2007, Rex IV and KeyBank executed a Second Amendment to the Credit Agreement, which extended the maturity date to the earlier to occur of (a) the closing date of a new senior credit facility of the Company or (b) December 31, 2007. On July 30, 2007, the Company made a payment of approximately $25.0 million on the Rex IV line of credit resulting in remaining indebtedness on the line of approximately $14.6 million as of July 31, 2007, which was subsequently paid in full with an advance from the Company’s new senior-secured line of credit (see Note #5).

The Reorganization Transactions resulted in the Company recognizing 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 the Company becoming subject to Federal and State income tax expense. Tax expenses had previously passed through to the partnership owners of the Predecessor Companies and were not recorded on the books of the Predecessor Companies.

On August 15, 2007, the underwriters in the initial public offering exercised their over-allotment option, causing the selling stockholders to sell an additional 600,000 shares of common stock to the underwriters on the same terms that the selling stockholders sold 800,000 shares to the underwriters in connection with the Company’s initial public offering. The over-allotment sale was consummated on August 20, 2007. The Company did not receive any proceeds from this sale of its common stock.

Earnings Per Share

Earnings per common share is computed by dividing consolidated net income by the weighted average number of common shares outstanding. Diluted earnings per common share is computed by dividing consolidated net income by the weighted average number of common shares outstanding during the period, including any potentially dilutive outstanding securities, such as options and warrants. Earnings per share is reflected prospectively from August 1, 2007, the date the Predecessor Companies were acquired by Rex Energy Corporation. Therefore, at September 30, 2007, the Company had consolidated operations for only two months in the fiscal year period for which earnings per share are relevant. At September 30, 2007, the Company had 30,794,720 common shares outstanding and no outstanding options, warrants, or other potentially dilutive securities.

Prior to the Reorganization Transactions, the Company’s business was conducted through a group of entities as to which there was no single holding entity. Each entity was separately owned by its then existing owners. As a result, there was no single capital structure upon which to calculate historical earnings per share information. Accordingly, earnings per share information has not been presented for historical periods prior to the Reorganization Transactions.

Revenue Recognition

Natural gas revenue is recognized when the natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of gas purchased (although there are provisions for challenging these measurements if the Company believes the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for natural gas purchases within 30-60 days of the end of each production month. The Company periodically reviews the difference between the dates of production and the dates it collects payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for the Company’s natural gas production is at its applicable field gathering system; therefore, the Company does not incur transportation costs related to its sales of natural gas production. The Company does not currently participate in any gas-balancing arrangements.

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Oil revenue is recognized when the oil is delivered to or collected by the purchaser, a sales agreement exists, collection for amounts billed is reasonably assured, and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves the Company’s stock tanks and enters the purchaser’s trucks. It is the measurement of the purchaser that determines the amount of oil purchased (although there are provisions for challenging these measurements if the Company believes the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil purchases within 30 days of the end of each production month. The Company periodically reviews the difference between the dates of production and the dates it collects payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for the Company’s oil production is at its applicable field gathering system; therefore, the Company does not incur transportation costs related to our sales of oil production.

The Company uses the allowance method to account for uncollectible accounts receivable. At both September 30, 2007 and December 31, 2006, management determined the allowance for uncollectible receivables to be approximately $173,000.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectibility of outstanding accounts receivable, fair values of financial derivative instruments, contingencies, and the results of current and future litigation. Oil and natural gas estimates, which are the basis for unit-of-production depletion, have numerous inherent uncertainties. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing, and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, and the Company’s ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.

Derivative Instruments

The Company uses put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of oil and natural gas. The Company accounts for these contracts using Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The results of these activities are reflected in the revenue section of the Consolidated Statements of Operations.

The Company has established the fair value of all derivative instruments using estimates determined by its counterparties. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values the Company reports in its consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments (including certain derivative instruments embedded in other contracts or agreements) be recorded at fair value and included in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the

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inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in earnings.

For derivative instruments designated as fair value hedges (in accordance with SFAS No. 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. However, the Company's evaluations are not documented, and as a result, the Company is recording changes on the derivative valuations through earnings.

Oil and Natural Gas Property, Depreciation and Depletion

The Company accounts for its natural gas and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. The Company periodically reviews its estimated proved reserve estimates and makes changes as needed to its depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in the Company’s estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is expensed over the life of the lease or transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years.

The Company accounts for impairment under the provisions of SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets.” When circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

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Goodwill and Intangible Assets

In accordance with SFAS No. 142,“Goodwill and Other Intangible Assets” (“SFAS 142”) no amortization is recorded for goodwill or intangible assets deemed to have indefinite lives for acquisitions completed after June 30, 2001. SFAS No. 142 requires that goodwill and non-amortizable assets be assessed annually for impairment. At September 30, 2007, the Company’s intangible assets consist of $31.8 million of goodwill and $1.3 million of intangible assets comprised of sales agreements that are amortized over an estimated useful life of five years. For the three months and nine months ended September 30, 2007 and 2006, the Company recorded amortization expense of $44,000 and $0, respectively. Amortization expenses were recorded only for those periods following the Reorganization Transactions. The Company is in the early stages of gathering data and performing an analysis and evaluation of the assets and liabilities assumed as of the date of acquisition. The Company has preliminarily estimated the excess cost over the fair values of those assets and liabilities. To the extent that the estimates used in the preliminary purchase price allocation need to be adjusted the Company will do so upon making that determination but not later than one year from the date of acquisition.

Goodwill and identified intangible assets that have an indefinite useful life are subject to impairment testing, which the Corporation conducts annually, or on an interim basis if events or changes in circumstances between annual tests indicate the assets might be impaired. The Corporation performs its annual impairment test for goodwill and identified intangible assets that have an indefinite useful life as of December 31 of each year. The impairment test involves a comparison of the fair value of each tangible and intangible asset to its carrying value. If the fair value is less than the carrying value, a further test is required to measure the amount of impairment.

Future Abandonment Cost

The Company accounts for future abandonment costs using SFAS No. 143,“Asset Retirement Obligations.” 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 the Company’s 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. The future abandonment cost is estimated by discounting the future cash outflows using a credit adjusted risk-free rate of 10.0%.

	September 30, 2007			December 31, 2006
	($ in Thousands)			($ in Thousands)
Beginning Balance	$	5,269		$	2,358
Initial Asset Retirement Obligation Capitalized		492			2,506
Plugging Costs Incurred		(10	)		(71	)
Asset Retirement Obligation Accretion Expense		408			476
Total Asset Retirement Obligation	$	6,159		$	5,269

Recently Adopted Accounting Pronouncements

In May 2007, the FASB issued FSP FIN 48-1,“Definition of Settlement in FASB Interpretation No. 48”, which amends FIN No. 48,“Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109”(“FIN 48”), to provide guidance on how an entity should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. FSP FIN 48-1 clarifies that a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits if the taxing authority has completed all of its required or expected examination procedures, the enterprise does not intend to appeal or litigate any aspect of the tax position, and it is considered remote that the taxing authority would reexamine the tax position. This guidance is effective upon initial adoption of FIN 48, which the Company adopted for its year ending December 31, 2007. The Predecessor Companies were treated as pass through entities for federal and state income tax purposes, therefore, the adoption of FIN 48 did not have an impact on results of operations and financial

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condition for the seven month periods ended July 31, 2007. The Company has evaluated the effects of FIN 48 and FSP FIN 48-1 upon the completion of the Reorganization Transactions, on July 30, 2007 and again as of September 30, 2007, and has determined they do not currently have a material impact on the results of operations or financial condition.

In April 2007, the FASB issued FASB Staff Position (“FSP”) on FASB Interpretation (“FIN”) 39–1,“Amendment of FASB Interpretation No. 39”(“FSP FIN 39-1”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39–1 is effective for fiscal years beginning after November 15, 2007. Rex Energy Corporation does not expect the implementation of FSP FIN 39–1 to have a material impact on its results of operations or financial condition.

On February 15, 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of SFAS No. 115. SFAS No. 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. Under SFAS No. 159, a business entity is required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS No. 159 is effective as of January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 159 will have on its results of operations and financial condition, but does not expect it will have a material impact.

In September 2006, the FASB issued SFAS No. 157,“Fair Value Measurements” (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, the Company will adopt the provisions of SFAS 157 for its year beginning January 1, 2008. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.

2. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS

New Albany

On September 7, 2007, the Company’s wholly owned subsidiary, Rex Energy I, LLC, acquired a thirty percent (30%) working interest in certain undeveloped oil and gas leases covering approximately 70,322 gross acres located in Lawrence, Orange, Washington and Jackson Counties in the State of Indiana for a purchase price of $1,054,855. The interests were acquired from Aurora Oil & Gas Corporation pursuant to an option granted to New Albany on January 27, 2006, the predecessor in interest of Rex Energy I, LLC. In connection with this sale, Aurora reserved a one-half of one percent (0.5%) overriding royalty interest in the conveyed properties.

Acquisition of Minority Interests

Pursuant to the Reorganization Transactions, Rex acquired interests in the Predecessor Companies from the predecessor owners. These interests were acquired through an exchange of common stock in Rex Energy Corporation.

This transaction has been accounted for partially as a transfer of interests under common control and, partially, as an acquisition of non-controlling interests in accordance with SFAS No. 141. The controlling interests of the Predecessor Companies were held by Lance T. Shaner. Those interests are reflected in the consolidated financial statements at the historical cost of the interests contributed. The non-controlling owner’s interests are accounted for using the purchase method of accounting under SFAS No. 141 and reflected as minority interests in the consolidated financial statements at the fair value of the interests contributed since these holders did not control the Predecessor Companies prior to the Reorganization Transactions.

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The total consideration paid for the minority interests in excess of cost was $92.8 million and reflects 8,437,521 shares of Rex Energy Corporation common stock, the fair value of which was based upon on the initial public offering price of $11.00 per share of common stock. Accordingly, the Company has reflected the acquired tangible assets at the fair value of the consideration paid. The excess of the purchase price over the fair value of the tangible assets acquired approximates $71.9 million and has been included in the captions Evaluated Oil and Gas Properties, Unevaluated Oil and Gas Properties and Intangible Assets in the Consolidated Balance Sheet as of September 30, 2007.

The finite-lived intangible assets related to the contractual right to future sales revenue from sales agreements was $1.3 million. The residual amount representing the purchase price in excess of tangible and intangible assets is $31.8 million and has been recorded as Goodwill.

The Company is in the early stages of gathering data and performing an analysis and evaluation of the assets and liabilities assumed as of the date of acquisition. The Company has preliminarily estimated the excess cost over the fair values of those assets and liabilities. To the extent that the estimates used in the preliminary purchase price allocation need to be adjusted, the Company will do so upon making that determination, but not later than one year from the date of acquisition. The Company has preliminarily determined the following fair values for the acquired assets and liabilities assumed as of the date of acquisition ($ in thousands):

Purchase Price	$	92,813
Minority interests		20,937
Goodwill		31,800
Finite-Lived Intangible Assets/Contractual Rights		1,328
Increase in Fair Value of Evaluated Property Assets		52,362
Increase in Fair Value of Unevaluated Property Assets		18,186
Deferred Tax Asset		2,100
Deferred Tax Liability		(33,900	)
Purchase Price Allocation	$	92,813

The estimated useful lives of the finite-lived intangibles are expected to be five years. The Company is amortizing these finite-lived intangibles over their estimated useful lives using the straight line method.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standard No. 107,“Disclosures About Fair Value of Financial Instruments.” The Company has determined the estimated fair value amounts by using available market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

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 the Company’s long-term debt instruments approximates the fair value as the debt facilities carry a market rate of interest.

The Company estimates the fair value of the participation liability associated with a prior NorGuard Insurance Company’s term loan to be $2,141,109 as of December 31, 2006. The participation liability was paid in full and extinguished on July 31, 2007.

The fair value of the net liability associated with the Company’s derivative instruments was $12,353,571 and $3,258,102 at September 30, 2007 and December 31, 2006, respectively. The fair value is based on valuation methodologies of the Company’s counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

4. COMMITMENTS AND CONTINGENCIES

Legal Reserves

At September 30, 2007, the Company’s Consolidated Balance Sheet included reserves for the legal proceedings relating to the arbitration proceeding of PennTex Resources against ERG Holdings, Inc. and Scott Y. Wood and the putative class action lawsuit filed in the United States District Court for the Southern District of

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Illinois against Rex Operating and PennTex Illinois in the amount of $441,956. At December 31, 2006, the Company’s Consolidated Balance Sheet included a reserve for the legal proceedings relating to the putative class action lawsuit in the amount of $891,000. 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 the Company could incur 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, the Company believes 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 the consolidated financial position or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Environmental

Due to the nature of the natural gas and oil business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. It conducts 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.

The Company manages its 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, management knows of no significant probable or possible environmental contingent liabilities.

Letters of Credit

The Company has posted $855,000, at September 30, 2007, in various letters of credit to secure its drilling and related operations.

Other

In addition to the Asset Retirement Obligation discussed in Note 1, the Company has withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts totaling $322,046 are included in Other Liabilities at September 30, 2007 and December 31, 2006.

5. SENIOR-SECURED LINES OF CREDIT AND LONG-TERM DEBT

On July 31, 2007, the Company used the proceeds from the initial public offering to repay all outstanding indebtedness under credit facilities of the Predecessor Companies with the exception of the Rex IV line of credit. A payment of approximately $25.0 million on the Rex IV line of credit was made resulting in remaining indebtedness on the line of approximately $14.6 million as of July 30, 2007. The remaining balance on the Rex IV line of credit was subsequently repaid in full with borrowings from the Company’s new senior-secured line of credit.

On September 28, 2007, Rex Energy Corporation (the “Company”) entered into a new credit agreement 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 “New Credit Agreement”). Borrowings under the New Credit Agreement are limited by a borrowing base that is determined in regard to the Company’s oil and gas properties. The borrowing base is $75 million; however, the New Credit Agreement provides that the revolving credit facility may be increased up to $200 million upon re-determinations of the

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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 New Credit Agreement mature on September 28, 2012, and in certain circumstances, the Company will be required to prepay the loans. At the Company’s election, borrowings under the New Credit Agreement 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 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. 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 New Credit Agreement provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding the Company’s oil and gas reserves attributable to the oil and gas properties of the Company and its subsidiaries, 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, the Company is required to furnish to the lenders a reserve report evaluating the oil and gas properties of the Company and its subsidiaries as of the immediately preceding January 1 and July 1. The reserve report as of January 1 of each year must be prepared by one or more independent petroleum engineers approved by the Administrative Agent. Any re-determined borrowing base will become effective on the subsequent April 1 and October 1. The Company, or the Administrative Agent at the direction of a majority of the lenders, may each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, the Company may request interim borrowing base re-determinations upon the proposed acquisition by the Company of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base.

The New Credit Agreement contains covenants that restrict the Company’s ability to, among other things, materially change the Company’s 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 New Credit Agreement also requires the Company to meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. Proceeds of the initial borrowing under the New Credit Agreement were used to repay, in full, and terminate the existing credit agreement of Rex Energy IV, LLC, a wholly owned subsidiary of the Company. The Company expects that subsequent borrowings under the New Credit Agreement will be used to finance the Company’s working capital needs, and for general corporate purposes in the ordinary course of its business, including the exploration, acquisition and development of oil and gas properties. Obligations under the New Credit Agreement are secured by mortgages on the oil and gas properties of the Company’s subsidiaries located in the states of Illinois and Indiana. The Company is required to maintain liens covering the oil and gas properties of the Company representing at least 80% of the total value of all oil and gas properties of the Company.

At September 30, 2007, the Company had a balance of approximately $18.2 million on the New Credit Agreement and had approximately $56.8 million available for future borrowings under the facility.

Rex IV had previously maintained a line of credit facility that had been paid in full and closed during the period ended September 30, 2007. This credit facility had a maturity date of less than one year and is categorized as a current liability on the combined balance sheet as of December 31, 2006. All long-term debt, loans and notes payable held by the Predecessor Companies, in addition to the Rex IV line of credit, were paid in full and the credit facilities closed during the three month period ended September 30, 2007.

In addition to the Company’s New Credit Agreement, the Company 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 to the Company. Long-term debt and lines of credit consists of the following at September 30, 2007 and December 31, 2006:

	September 30, 2007			December 31, 2006
	($ in Thousands)			($ in Thousands)
Douglas M&T Loan	$	0		$	8,941
PennTex M&T Credit Facility		0			14,944
Rex II Credit Facility		0			3,550
Rex III Credit Agreement		0			20,000
Line of Credit – Rex IV		0			37,581
Senior-Secured Lines of Credit		18,186			0
Other Loans and Notes Payable		57			874
Total Debts		18,243			85,890
Less Current Lines of Credit and Current Portion of Long-Term Debt		(29	)		(40,448	)
Total Senior-Secured Lines of Credit and Long-Term Debts	$	18,214		$	45,442

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6. FINANCIAL DERIVATIVE INSTRUMENTS

The Company’s 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, the Company entered into oil and natural gas derivative instruments. As of September 30, 2007 and December 31, 2006, the Company’s oil and natural gas derivative instruments consisted of fixed rate swap contracts and collars. These instruments allow the Company to predict with greater certainty the effective oil and natural gas price to be received for the Company’s hedged production.

Collars contain a fixed floor price (put) and ceiling price (call). The put options are purchased from the counterparty by the Company’s payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays the Company 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 by the Company’s receipt of a cash premium. If the market price is greater than the call strike price for a calculation period, then the Company pays the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

The Company sells oil and natural gas in the normal course of business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in oil and natural gas sales.

The Company enters into derivative instruments such as swap contracts to hedge a portion of its forecasted oil and natural gas sales.

The Company received (incurred) net payments of ($1,975,162) and ($4,225,643) under these derivative instruments during the nine months ended September 30, 2007 and 2006, respectively. Unrealized gains (losses) associated with these derivative instruments are included in other income(expense) and amounted to ($9,095,471) and $5,523,776 for the nine months ended September 30, 2007 and 2006, respectively.

The Company’s open asset/ (liability) financial derivative instrument positions at September 30, 2007 consisted of:

Period	Contract Type	Volume	Average Derivative Price	Fair Market Value ($ in Thousands)
Oil
2007	Swaps	84,000 Bbls	$65.78	$	(1,532	)
2007	Collars	87,000 Bbls	$ 53.45 – 64.57	$	(1,394	)
2008	Swaps	204,000 Bbls	$65.58	$	(2,129	)
2008	Collars	369,000 Bbls	$ 62.33 – 80.26	$	(1,097	)
2009	Swaps	192,000 Bbls	$64.00	$	(1,686	)
2009	Collars	350,000 Bbls	$ 62.30 – 67.95	$	(2,383	)
2010	Swaps	180,000 Bbls	$62.20	$	(1,566	)
2010	Collars	288,000 Bbls	$ 60.00 – 78.25	$	(446	)
	Total	1,754,000 Bbls		$	(12,233	)
Natural gas
2007	Swaps	30,000 Mcf	$7.54	$	19
2007	Collars	180,000 Mcf	$ 7.56 – $14.08	$	159
2008	Collars	840,000 Mcf	$ 7.00 – 9.19	$	(71	)
2009	Collars	600,000 Mcf	$ 7.00 – 9.00	$	(228	)
	Total	1,650,000 Mcf		$	(121	)

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7. INCOME TAXES

The Company accounts 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 have been recognized in the Company’s 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. The Company recorded entries on August 1, 2007 to recognize the deferred tax liabilities and assets that were passed-through to the consolidated corporation from its Predecessor Companies. Prior to consolidating the Predecessor Companies through the acquisition of minority interests, the combined Predecessor Companies did not reflect such deferred assets or liabilities on their financial statements.

Effective August 1, 2007, the Company 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 uncertain tax positions. This interpretation requires companies to recognize in their financial statements the impact of a tax position, if that position is more likely than not of being sustained in audit, based on the technical merits of the position.

The Predecessor Companies are treated as partnerships for federal and state income tax purposes. Accordingly, income taxes are not reflected in the consolidated financial statements because the resulting profit or loss is included in the income tax returns of the individual stockholders, members or partners. Income tax expense has been presented for the Company on the consolidated statement of operations prospectively for periods after August 1, 2007.

The Company will file consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. The Company is subject to U.S. Federal income tax examinations and to various state tax examinations for periods after August 1, 2007. The Company’s practice is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. The Company does not have any accrued interest or penalties as of September 30, 2007.

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

	Rex Energy Corporation Two months Ended September 30, 2007 ($ in Thousands)
Net loss before minority interests and income taxes	$	(11,837	)
Pre-tax loss prior to reorganization not subject to federal income taxes		11,724
Net loss before income taxes	$	(113	)
Statutory U.S. income tax rate		34	%
Tax benefit recognized using statutory U.S. income tax rate	$	38
State income tax benefit		7
Other		—
Income tax benefit	$	45
Effective income tax rate		40.2	%

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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, 2007. The combined Predecessor Companies at December 31, 2006 were comprised of limited partnerships, limited liability companies, and subchapter S corporations whose tax liability passed to the various members, partners, and stockholders in those respective entities. Accordingly, no deferred tax liabilities or assets were recognized by those entities at December 31, 2006:

	Rex Energy Corporation September 30, 2007 ($ in Thousands)
Tax effects of temporary differences for:
Current:
Assets:
Unrealized loss on derivatives	$	2,120
Net Operating Loss carryforward		737
Other		188
Total current deferred tax assets		3,045
Long-Term:
Assets:
Asset Retirement Obligation		2,482
Unrealized loss on derivatives		2,859
Other		1,026
Total long-term deferred tax assets		6,367
Liabilities:
Book basis of oil and gas properties in excess of tax basis		(41,167	)
Net long-term deferred tax liability	$	(34,800	)

8. LITIGATION

PennTex Resources – Wood Arbitration

On August 20, 2007, the arbitration panel convened by the American Arbitration Association in Houston, Texas issued its findings and awards in the 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 panel awarded Wood the amount of $92,540.07 for attorney’s fees and expenses incurred by Wood relative to prosecuting his counterclaims in a lawsuit in the 334th Judicial District Court of Harris County, Texas, cause number 2004-39584, styled“ERG Illinois, Inc. And Scott Y. Wood v. Tsar Energy II, LLC And Richard M. Cheatham” (the “Tsar Case”). The panel found or awarded PennTex Resources the following: (a) with respect to its claim for post-closing purchase price adjustments under the terms of a stock purchase agreement entered into by the parties in January 2005 (the “2005 Stock Purchase Agreement”), ERG Holdings was required to pay PennTex Resources $88,776.60, with interest at 6% per annum until paid, (b) ERG Holdings and Wood were required to return the original and all copies of a $1,000,000 letter of credit previously provided by PennTex Resources pursuant to the 2005 Stock Purchase Agreement and ordered not to draw upon or attempt to draw upon the letter of credit conditioned upon PennTex Resources’ payment of Wood’s attorney’s fees and expenses related to his counterclaims in Tsar Case, (c) Wood was required to promptly provide PennTex Resources with a signed release or dismissal of his claims filed in the Tsar Case, (d) Wood was ordered to pay PennTex Resources $217,428.76 in attorney’s fees relating to PennTex Resources’ federal court litigation to require Wood to appear before the arbitration panel and its release obligation claim, (e) ERG Holdings was ordered to pay PennTex Resources $67,877.99 for attorneys fees and expenses incurred by PennTex Resources in pursuing its claims against ERG Holdings, (f) Wood was ordered to

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pay PennTex Resources $14,302 for expenses incurred by PennTex Resources relative to the arbitration, (g) ERG Holdings was ordered to pay PennTex Resources $7,368.25 for expenses incurred relative to the arbitration and (h) Wood and ERG Holdings were ordered to reimburse PennTex Resources the sum of $3,625 for fees and expenses of the American Arbitration Association. As a result of the arbitration panel’s award, Wood is required to pay PennTex Resources a total of $141,003.19 (after deducting legal fees and expenses payable by PennTex Resources to Wood in the amount of $92,540.07 relative to Wood’s counterclaims in the Tsar Case) and ERG Holdings is required to pay PennTex Resources a total of $165,835.34, thus resulting in a total cash award to PennTex Resources of $306,838.53.

On September 13, 2007, PennTex Resources filed a motion for confirmation of the arbitration award and for final judgment with the U.S. District Court for the Southern District of Texas, Houston Division in the pending federal lawsuit entitled“Scott Y. Wood and ERG Holdings, Inc. v. PennTex Resources, L.P. and Lance T. Shaner,” civil action no. H-06-2198. In the motion, PennTex Resources also sought the dismissal of Lance T. Shaner as a party to the action, such motion being granted by the court on September 28, 2007. See Note 9—“Subsequent Events.”

9. SUBSEQUENT EVENTS

PennTex Resources – Wood Arbitration

On October 11, 2007, in the matter of“Scott Y. Wood and ERG Holdings, Inc. v. PennTex Resources, L.P.”, civil action no. H-06-2198, in the U.S. District Court for the Southern District of Texas, Houston Division, Scott Y. Wood filed a motion seeking to vacate the August 20, 2007 award of the arbitration panel convened by the American Arbitration Association in Houston, Texas and opposing PennTex Resources’ motion to confirm the award. See Note 8—“Litigation.” In the motion, Wood moved for vacatur of the award on grounds that the arbitration panel exceeded its powers by issuing a decision based upon clearly erroneous findings of fact. On October 31, 2007, PennTex Resources filed a motion in opposition to Wood’s motion to vacate the arbitration award.

Oil And Gas Property Acquisitions

On October 12, 2007, the Company’s wholly owned subsidiary, Rex Energy I, LLC, acquired a forty percent (40%) working interest in certain undeveloped oil and gas leases covering approximately 5,878 net acres located in Knox County in the State of Indiana. The interests were acquired from HAREXCO, Inc., an Illinois corporation doing business in the State of Indiana under the assumed name of Harris Energy Company (“Harris Energy”), for a purchase price of $235,133.16. In connection with this sale, Harris Energy reserved a four percent (4.0%) of forty percent (40.0%) overriding royalty interest in the conveyed properties and a ten percent (10.0%) of forty percent (40.0%) back-in-after-payout working interest in the first five net wells drilled on the acquired properties, the properties previously acquired from Harris Energy on May 24, 2007, or any other properties which are subsequently acquired from Harris Energy. Rex Energy I, LLC was obligated to purchase the above interests pursuant to the terms of a purchase and sale agreement dated May 24, 2007, which was previously entered into by its predecessor in interest, Rex II.

Stock Option Grants

On November 6, 2007, the Company granted nonqualified options to purchase an aggregate of 675,000 shares of common stock of the Company to 25 employees under the Company’s 2007 Long-Term Incentive Plan (the “Plan”). Each of the options granted have an exercise price of $9.99 per share, the closing price for the Company’s common stock on the NASDAQ National Market on the date of the grant. Each option vests and is exercisable on the third anniversary of the grant date provided that the employee is employed by the Company on that date. The options are subject to early vesting in the event that certain events occur, including the death, permanent disability or retirement of the employee or a change in control of the Company (as such term is defined in the Plan). The options granted expire if not exercised on or before November 5, 2017.

On November 7, 2007, the Company granted nonqualified options to purchase common stock of the Company to Lance T. Shaner, Daniel J. Churay, John W. Higbee and John A. Lombardi, the non-employee directors of the Company. Mr. Shaner, Mr. Churay and Mr. Higbee each received an option to purchase 25,000 shares of common stock and Mr. Lombardi received an option to purchase 75,000 shares of common stock. Each of the options granted have an exercise price of $9.50 per share, the closing price for the Company’s common stock on the NASDAQ National Market on the date of the grant. The options vest and are exercisable in one-third increments on the first, second and third anniversaries of the date of the grant. The options are subject to early vesting in the event that certain events occur, including the death or permanent disability of the non-employee director, the failure of the stockholders to re-elect the non-employee director to the Company’s Board of Directors, the resignation of the non-employee director as a direct result of a vote of the Company’s stockholders, or a change in control of the Company (as such term is defined in the Plan). The options granted expire if not exercised on or before November 6, 2017.

The Plan is administered by the Compensation Committee of the Company’s Board of Directors. Under the terms of the Plan, the Compensation Committee determines the individuals to receive grants under the Plan, the number of shares of common stock underlying any granted stock options, the terms relating to vesting and excising any granted stock options, and the exercise price of the stock option. The Company is in the process of determining the value of the granted stock options and expects to recognize compensation expense over the vesting periods of the options.

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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 certain aspects of the Company’s 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, 2006 included in our prospectus dated July 24, 2007 filed with SEC on July 26, 2007 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 Operations

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2007		2006		2007		2006
Production:
Oil (Bbls)		208,081		143,886		606,677		378,523
Natural gas (Mcf)		299,675		256,953		846,245		825,918
Total (BOE)a		258,027		186,712		747,718		516,176
Average daily production:
Oil (Bbls)		2,262		1,564		1,662		1,037
Natural gas (Mcf)		3,261		2,793		2,319		2,263
Total (BOE)a		2,805		2,029		2,739		1,414
Average sales prices:
Oil (per Bbl)	$	70.78	$	66.26	$	61.84	$	63.82
Natural gas (per Mcf)	$	6.21	$	6.39	$	6.81	$	7.26
Total (per BOE)a	$	64.30	$	59.85	$	57.88	$	58.42
Average NYMEX pricesb
Oil (per Bbl)	$	75.38	$	70.47	$	66.19	$	68.22
Natural gas (per Mcf)	$	6.03	$	6.58	$	6.78	$	7.45

^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,
	2007			2006			2007			2006
Appalachian
Revenues – Natural Gas ($ in Thousands)	$	1,192		$	1,095		$	4,015		$	4,317
Volumes (MCF)		184,702			160,221			557,455			540,702
Average Price	$	6.45		$	6.83		$	7.20		$	7.98
Illinois
Revenues – Oil ($ in Thousands)	$	13,639		$	8,895		$	35,398		$	22,215
Volumes (BBL)		192,686			134,373			573,422			346,779
Average Price	$	70.78		$	66.19		$	61.73		$	64.06
Permian
Revenues – Oil ($ in Thousands)	$	1,090		$	639		$	2,117		$	1,943
Volumes (BBL)		15,395			9,513			33,255			31,744
Average Price	$	70.79		$	67.21		$	63.67		$	61.22
Revenues – Natural Gas ($ in Thousands)	$	670		$	546		$	1,751		$	1,680
Volumes (MCF)		114,973			96,732			288,790			285,216
Average Price	$	5.83		$	5.64		$	6.06		$	5.89
	Other Performance Measurements
	For Three Months Ended September 30,						For Nine Months Ended September 30,
	2007			2006			2007			2006
EBITDAX	$	7,515		$	4,809		$	18,106		$	13,871
LOE per BOE	$	22.90		$	22.54		$	24.52		$	18.65
G&A as a Percentage of Operating Revenue		11.8	%		10.0	%		13.0	%		10.1	%

General Overview

Operating revenue increased 50.1% for the third quarter of 2007 over the same period of 2006. 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 2007, production increased 38.2% to 258,027 BOE over the same period in 2006 due to the continued success of our drilling programs and our acquisitions. Realized losses on derivative activities increased by 32.3% to $1.6 million for the third quarter of 2007 as compared to the same period in 2006.

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Operating expenses increased $5.7 million, or 71.7%, as compared to the same period in 2006. Operating expenses are primarily comprised of production expenses, general and administrative expenses, and depreciation, depletion, amortization, and accretion expenses. These increases were due, in part, to acquisitions consummated in the final six months of 2006 within the Illinois basin whereby we acquired all of the oil producing assets owned by Tsar Energy II, L.L.C. and certain oil producing assets owned by Team Energy, L.L.C. and its affiliates. The increase is also partially attributed to approximately $890,000 of increased depletion and amortization expenses realized over the two month period ending September 30, 2007 resulting from a step-up in book basis of assets caused by the acquisition of all minority interests from the Predecessor Companies.

EBITDAX, is used as a financial measure by our management team 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 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 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 $2.7 million and $4.3 million to $7.5 million and $18.1 million, respectively, for the three and nine month periods ended September 30, 2007 as compared to the same periods in 2006. These increases are primarily a result of increased production and sales revenue in the three and nine month periods ended September 30, 2007 as compared to the same periods in 2006.

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 presents 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 $.36 and $5.87, respectively, for the three and nine month periods ended September 30, 2007 as compared to the same periods in 2006. We have experienced higher lifting costs in the 2007 periods as compared to 2006 in part due to acquisitions we completed in the final six months of 2006. Those acquisitions, which were waterflood oil fields in the Illinois Basin, had higher average lifting costs than we had previously recognized on average.

G&A expenses as a percentage of operating revenue measures overhead costs associated with the management and operation of the company. G&A expenses as a percentage of revenue increased to approximately 11.8% for the three month period ended September 30, 2007 as compared to 10.0% for the same period in 2006. G&A expense as a percentage of revenue for the nine month period ended September 30, 2007 was 13.0% as compared to 10.1% for the same nine month period in 2006. The increases to G&A expense as a percentage of revenue in both the three and nine month periods were caused in part by increases to G&A expense resulting from our preparation for the Reorganization Transactions and in part by the loss of operator overhead revenues that offset G&A expenses as a result of our acquisition of oil producing properties from Tsar Energy II, L.L.C. in the final quarter of 2006, partially offset by increased sales revenues.

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Comparison of the Three Months Ended September 30, 2007 to Three Months Ended September 30, 2006

Oil and gas revenue for the three months ended September 30, 2007 and 2006 (in thousands) is summarized in the following table:

	Three Months Ended September 30,
	2007			2006			(Change)			%
Oil and gas Revenues:
Oil sales revenue	$	14,729		$	9,534		$	5,195		54.5	%
Oil derivatives realized		(1,888	)		(1,598	)		(290	)	18.1	%
Total oil revenue	$	12,841		$	7,936		$	4,905		61.8	%
Gas sales revenue	$	1,862		$	1,641		$	221		13.5	%
Gas derivatives realized		295			394			(99	)	(25.1	)%
Total gas revenue	$	2,157		$	2,035		$	122		6.0	%
Consolidated sales	$	16,591		$	11,175		$	5,416		48.5	%
Consolidated derivatives realized		(1,593	)		(1,204	)		(389	)	32.3	%
Total oil & gas revenue	$	14,998		$	9,971		$	5,027		50.4	%
Total BOE Production		258,027			186,712			71,315		38.2	%
Average Realized Price per BOE	$	58.12		$	53.40		$	4.72		8.8	%

Average realized price received for oil and gas during the third quarter of 2007 was $58.12 per BOE, an increase of 8.8%, or $4.72 per BOE, from the same quarter in the prior year. The average price for oil in the third quarter of 2007 increased 6.8% or $4.52 per barrel, whereas the average price for natural gas decreased 2.8%, or $0.18 per Mcf, from the same quarter in 2006. Our derivative activities effectively decreased net realized prices by $6.17 per BOE in the third quarter of 2007 and $6.45 per BOE in the third quarter of 2006.

Production volumesincreased 38.2% from the third quarter of 2006 primarily due to acquisitions in the Illinois Basin and continued success with our oil and gas well drilling activities. Our production for the third quarter averaged approximately 2,805 BOE per day of which 74.7% was attributable to the Illinois basin, 11.9% to the Appalachian basin, and 13.4% to activities in the Southwestern region.

Other operating revenue for the three months ended September 30, 2007 increased $23,000 to $130,000 from $107,000 for the same period in 2006. We generate other operating revenue from various activities such as revenue from the transportation of natural gas and disposal of salt water from non-related parties through a salt water disposal facility we own and operate for our own oil and gas production activities in the Southwestern region.

Production and lease operating expenses increased approximately $1.7 million, or 40.4%, in the third quarter of 2007 from the same period in 2006. These expenses typically increase as we add new wells and make certain improvements to existing wells in production. These increases were principally due to acquisitions consummated in the final six months of 2006 within the Illinois basin from Tsar Energy II, L.L.C. and Team Energy, L.L.C. and its affiliates.

General and administrative expenses for the third quarter of 2007 increased approximately $784,000, or 77.9%, to $1.8 million from the same period in 2006 primarily as a result of oil and gas property acquisitions in the Illinois basin during the final six months of 2006 which resulted in reduced overhead income on wells that we operated for Tsar Energy II, L.L.C. This overhead income had offset general and administrative expenses. In October of 2006, we acquired all of the interest of Tsar Energy II, L.L.C. in these wells, at which time we ceased to recognize the overhead income associated with these wells.

Depreciation, depletion, amortization, and accretion (“DD&A”) expenses for the three months ended September 30, 2007 increased approximately $3.2 million, or 119%, from $2.6 million for the same period in 2006. This increase was partially due to an increase in production volumes resulting from the Tsar Energy II, L.L.C. and Team Energy, L.L.C. acquisitions in the Illinois basin. The increase is also partially attributed to approximately $890,000 of increased depletion and amortization expenses realized over the two month period ending September 30, 2007 resulting from a step-up in book basis of assets caused by the acquisition of minority interests from the Predecessor Companies.

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Interest expense, net of interest income for the three months ended September 30, 2007 was approximately $933,000 as compared to $1.5 million for the same period in 2006. The decrease of $570,000 is primarily due to the decrease in the average balance on our long-term debt, lines of credit, and other loans and notes payable which have been significantly reduced with the proceeds of our initial public offering, which closed July 30, 2007.

Gain on sale of oil and gas properties for the three months ended September 30, 2007 was approximately $3,000 as compared to $0 for the same period in 2006. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively utilized by us and a gain or loss may be recognized when such an asset is sold.

Unrealized loss on oil and gas derivativesincludes a loss of approximately $2.4 million for the third quarter of 2007 as compared to a gain of $6.1 million for the same period in 2006. These changes are attributed 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 a 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) increased by 260% to $85,000 for the three months ended September 30, 2007 from approximately $53,000 of expense for the same period in 2006. The change during the three month period ended September 30, 2007 as compared to the same period in 2006 is primarily due to the recognition of gains on sale of scrap inventory.

Net loss before minority interests for the three months ended September 30, 2007 was approximately $1.7 million, a decrease of approximately $8.4 million from net income of approximately $6.7 million for the same period in 2006 as a result of the factors described above. All of the minority interests were acquired as part of the Reorganization Transactions on July 30, 2007.

Comparison of the Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006,

Oil and gas revenue for the nine months ended September 30, 2007 and 2006 (in thousands) is summarized in the following table:

	Nine Months Ended September 30,
	2007			2006			(Change)			%
Oil and gas Revenues:
Oil sales revenue	$	37,515		$	24,159		$	13,356		55.3	%
Oil derivatives realized		(2,467	)		(4,769	)		2,302		48.3	%
Total oil revenue	$	35,048		$	19,390		$	15,658		80.8	%
Gas sales revenue	$	5,766		$	5,996		$	(230	)	(3.8	)%
Gas derivatives realized		492			543			(51	)	(9.4	)%
Total gas revenue	$	6,258		$	6,539		$	(281	)	(4.3	)%
Consolidated sales	$	43,281		$	30,155		$	13,126		43.5	%
Consolidated derivatives realized		(1,975	)		(4,226	)		2,251		53.3	%
Total oil & gas revenue	$	41,306		$	25,929		$	15,377		59.3	%
Total BOE Production		747,718			516,176			231,542		44.9	%
Average Realized Price per BOE	$	55.24		$	50.23		$	5.01		10.0	%

Average realized prices received for oil and gas during the first nine months of 2007 was $55.24 per BOE, an increase of 10.0%, or $5.01 per BOE, from the same period in the prior year. The average price for oil in the nine month period of 2007 decreased 3.1%, or $1.99 per barrel, whereas the average price for natural gas decreased 6.2%, or $0.45 per Mcf, from the same period in 2006. Our derivative activities effectively decreased net realized prices by $2.64 per BOE in the first nine months of 2007 and $8.19 per BOE in the first nine months of 2006.

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Production volumesfor the first nine months of 2007 increased 44.9% from the same period in 2006 primarily due to acquisitions in the Illinois basin and continued success with our oil and gas well drilling activities. Our production for the first nine months of 2007 averaged approximately 2,739 BOE per day of which 76.7% was attributable to the Illinois basin, 12.4% to the Appalachian basin and 10.9% the Southwestern region.

Other operating revenue for the nine months ended September 30, 2007 decreased $15,000 to $343,000 from $358,000 for the same period in 2006. We generate other operating revenue from various activities such as revenue from the transportation of natural gas and disposal of salt water from non-related parties through a salt water disposal facility we own and operate for our own oil and gas production activities in the Southwestern region.

Production and lease operating expenses increased approximately $8.7 million, or 90.5%, in the first nine months of 2007 as compared to the same period in 2006. These expenses typically increase as we add new wells and make certain improvements to existing wells in production. These increases were principally due to acquisitions consummated in the final six months of 2006 from Tsar Energy II, L.L.C. and Team Energy, L.L.C. and its affiliates.

General and administrative expenses for the first nine months of 2007 increased approximately $2.7 million, or 103.0%, to $5.4 million from the same period in 2006 primarily as a result of oil and gas property acquisitions in the Illinois basin during the final six months of 2006 which resulted in reduced overhead income on wells which we operated for Tsar Energy II, L.L.C. This overhead income had offset general and administrative expenses. In October of 2006, we acquired all the interests of Tsar Energy II, L.L.C. in these wells, at which time we ceased to recognize the overhead income associated with these wells.

Exploration expenses for the first nine months of 2007 increased to $1.7 million from $0 for the same period in 2006 as a result of unsuccessful drilling efforts on a single well in our Southwestern region. We do not anticipate any additional charges to be incurred related to plugging this well.

Depreciation, depletion, amortization, and accretion (“DD&A”) expenses for the first nine months of 2007 increased approximately $7.1 million, or 52.8%, from $6.3 million for the same period in 2006. This increase was primarily due to an increase in production volumes resulting partially from the Tsar Energy II, L.L.C. and Team Energy, L.L.C. acquisitions in the Illinois basin. The increase is also partially attributed to approximately $890,000 of increased depletion and amortization expenses realized over the two month period ending September 30, 2007 resulting from a step-up in book basis of assets caused by the acquisition of minority interests from the Predecessor Companies.

Interest expense, net of interest income for the first nine months of 2007 was approximately $5.3 million as compared to $3.4 million for the same period in 2006. The increase of $1.9 million, or 55.7%, was largely attributable to increases in the average debt balance during the seven month period ended July 31, 2007, this increase was partially offset by the decrease in the average balance for the two month period ended September 30, 2007 caused by the repayment of debt with the proceeds of our initial public offering, which closed July 30, 2007.

Gain on sale of oil and gas properties for the nine months ended September 30, 2007 was approximately $195,000 as compared to $91,000 for the same period in 2006. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively utilized by us and a gain or loss may be recognized when such an asset is sold.

Unrealized loss on oil and gas derivativesincludes a loss of approximately $9.1 million for the first nine months of 2007 as compared to a gain of $5.5 million for the same period in 2006. These changes are attributed 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 imply the opposite. Our derivative program is designed to provide us with a greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

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Other income (expense) increased by 100% to income of $137 for the nine months ended September 30, 2007 from an expense of approximately $220,000 for the same period in 2006. The change during the nine month period ended September 30, 2007 as compared to the same period in 2006 is primarily due to the recognition of gains on the sale of scrap inventory.

Net loss before minority interests for the nine months ended September 30, 2007 was approximately $11.8 million, a decrease of approximately $21.2 million from net income of approximately $9.4 million for the same period in 2006 as a result of the factors described above. All of the minority interests were acquired as part of the Reorganization Transactions on July 30, 2007.

Capital Resources and Liquidity

Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to a group of banks to secure our senior credit facilities. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We borrow funds on the senior credit facilities as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our acquisitions, development or exploration programs, we may also suffer a reduction in our operating cash flow and access to funds under the senior credit facilities. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations, particularly China and India. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations have been primarily used to fund exploration and development of our oil and gas interests.

Financial Condition and Cash Flows for the Nine Months Ended September 30, 2007 and 2006

The following table summarizes our sources and uses of funds for the periods noted ($ in thousands):

	Nine Months Ended September 30, ($ in Thousands)
	2007			2006
Cash flows provided by operations	$	11,549		$	10,484
Cash flows used in investing activities		(25,666	)		(51,905	)
Cash flows provided by financing activities		14,109			39,451
Net increase (decrease) in cash and cash equivalents	$	(8	)	$	1,970

Net cash provided by operating activities increased by approximately $1.1 million in the first nine months of 2007 over the same period in 2006. The increase in 2007 was affected by a combination of factors including increased sales volumes from acquisitions in 2006, an increase in accounts receivable, increases to inventory, prepaid expenses, and other assets, decreased accounts payable and increased commodity prices; partially offset by decreases in net other assets and liabilities. Average realized prices increased from $50.23 per BOE in the first nine months of 2006 to $55.24 per BOE in the first nine months of 2007. Our production volumes increased 44.9% to 747,718 BOE in first nine months of 2007 from 516,176 BOE in the first nine months of 2006.

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Net cash used in investing activities decreased approximately $26.2 million, or 50.6%, from the first nine months of 2006 to $25.7 million in the first nine months of 2007. The decrease was the result of a reduction of approximately $41.0 million in the acquisitions of property and equipment partially offset by an increase of $148,000 in proceeds related to the sale of other assets, these decreases were partially offset by an increase of approximately $13.8 million for development of oil & gas properties.

Net cash provided by financing activities decreased approximately $25.3 million, or 64.2%, from the first nine months of 2006 to $14.1 million in the first nine months of 2007. The change resulted primarily from increased repayments on long term debts, lines of credit and other notes payable, and participation liabilities of $107.4 million; partially offset by a decrease in payments to related parties, reduced debt issuance costs, increased proceeds from the sale of stock, decreased capital contributions, and reduced cash distributions of approximately $6.2 million, $303,000, $87.9 million, $19.4 million, and $7.1 million, respectively.

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 (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on us.

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

We discuss critical accounting policies and recently adopted and issued accounting standards in Item 1.Consolidated Financial Statements—Note 1,“Summary of Significant Accounting Policies.”

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 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 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 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 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 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 we believe this measure is commonly reported and widely used by

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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 our 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 EBITDAX assists our lenders and investors in comparing a company’s 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. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Additionally, 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 income determined under GAAP and EBITDAX to evaluate our performance.

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

	Three Months Ended September 30,						Nine Months Ended, September 30,
	2007			2006			2007			2006
Net Income (Loss)	$	(810	)	$	4,127		$	(5,640	)	$	5,310
Add Back Depletion, Depreciation & Amortization		5,954			2,735			13,862			6,601
Add Back Interest Expense		935			1,507			5,285			3,472
Add Back Exploration & Impairment Expenses		—			—			1,704			—
Less Interest Income		(2	)		(4	)		(3	)		(80	)
Add Back Unrealized Losses from Financial Derivatives		2,361			(6,098	)		9,095			(5,524	)
Add Back Minority Interest Share of Net Income (Loss)		(878	)		2,542			(6,152	)		4,091
Add Back (Less) Income Tax Expense (Benefit)		(45	)		—			(45	)		—
EBITDAX	$	7,515		$	4,809		$	18,106		$	13,870

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. See Note 1 – “Summary of Significant Accounting Policies.”

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.

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For the three month periods ended September 30, 2007 and 2006, the net realized loss on oil and natural gas derivatives was approximately $1.6 million and $1.2 million, respectively. For the nine month periods ended September 30, 2007 and 2006, the net realized loss on oil and natural gas derivatives was approximately $2.0 million and $4.2 million, respectively. The losses are reported as net realized loss on derivatives in the Consolidated Statements of Income.

For the three month period ended September 30, 2007, the net unrealized loss on oil and natural gas derivatives was approximately $2.4 million as compared to a net unrealized gain of approximately $6.1 million on oil and natural gas derivatives for the same period in 2006. For the nine month period ended September 30, 2007, the net unrealized loss on oil and natural gas derivatives was approximately $9.1 million as compared to a net unrealized gain of approximately $5.5 million on oil and natural gas derivatives for the same period in 2006. The net unrealized gains and losses are reported as net unrealized gains (losses) on derivatives in the Consolidated Statements of Income.

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. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time. Additional information related to our outstanding oil and natural gas derivative positions can be found in Note 7 to the consolidated financial statements.

For a summary of our current oil and natural gas derivative positions at September 30, 2007 refer to Note 4 of the Consolidated and Combined Financial Statements, “Financial 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 derivative 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 utilize include swaps and collars. The volume of derivative instruments that we may utilize 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 provide 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 derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity underlying such derivatives. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives.

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 ABR based 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 Securities and Exchange Commission’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, 2007, 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 Securities and Exchange Commission 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.

PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

The information contained in Part I, Item 1, Note 8, “Litigation,” and Note 9, “Subsequent Events, PennTex Resources – Wood Arbitration,” of this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item 1A. Risk Factors.

During the quarter ended September 30, 2007, there were no material changes to the risk factors previously reported by the Company in its prospectus dated July 24, 2007 filed with the Securities and Exchange Commission on July 26, 2007.

Item 6. Exhibits.

Exhibit Number	Exhibit Title
10.1+	Rex Energy Corporation 2007 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the registrant’s Registration Statement on Form S-1/A filed on June 11, 2007).
10.2+	Employment Agreement by and between Benjamin W. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

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10.3+	Employment Agreement by and between Thomas F. Shields and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).
10.4+	Employment Agreement by and between Thomas C. Stabley and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).
10.5+	Employment Agreement by and between Christopher K. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).
10.6+	Employment Agreement by and between William L. Ottaviani and Rex Energy Operating Corp. dated August 8, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 14, 2007).
10.7	Credit Agreement, dated as of September 28, 2007, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, BNP Paribas, as Syndication Agent, Sovereign Bank, as Documentation Agent and The Lenders Party Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).
10.8	Guaranty and Collateral Agreement, dated as of September 28, 2007, made by Rex Energy Corporation and each of the other grantors (as defined therein) in favor of KeyBank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).
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.

+ Indicates management compensatory plan, contract or arrangement.

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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 14, 2007	By:	/s/ Benjamin W. Hulburt
		Chief Executive Officer
		(Principal Executive Officer)
Date: November 14, 2007	By:	/s/ Thomas C. Stabley
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibit Number	Exhibit Title
10.1+	Rex Energy Corporation 2007 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the registrant’s Registration Statement on Form S-1/A filed on June 11, 2007).
10.2+	Employment Agreement by and between Benjamin W. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).
10.3+	Employment Agreement by and between Thomas F. Shields and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).
10.4+	Employment Agreement by and between Thomas C. Stabley and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).
10.5+	Employment Agreement by and between Christopher K. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).
10.6+	Employment Agreement by and between William L. Ottaviani and Rex Energy Operating Corp. dated August 8, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 14, 2007).
10.7	Credit Agreement, dated as of September 28, 2007, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, BNP Paribas, as Syndication Agent, Sovereign Bank, as Documentation Agent and The Lenders Party Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).
10.8	Guaranty and Collateral Agreement, dated as of September 28, 2007, made by Rex Energy Corporation and each of the other grantors (as defined therein) in favor of KeyBank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).
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.

+ Indicates management compensatory plan, contract or arrangement.

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