REX ENERGY CORP - FORM 10-Q

REX ENERGY CORP - FORM 10-Q - August 4, 2010

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EX-31.2 - SECTION 302 CFO CERTIFICATION - REX ENERGY CORP	dex312.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - REX ENERGY CORP	dex311.htm
EX-32.1 - SECTION 906 CEO AND CFO CERTIFICATION - REX ENERGY CORP	dex321.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

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

For the transition period from to .

Commission file number: 001-33610

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

20-8814402

(State or other jurisdiction of

incorporation or organization)

(I.R.S. employer

identification number)

476 Rolling Ridge Drive, Suite 300

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes ¨ No ¨

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

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

44,049,533 common shares were outstanding on August 3, 2010.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD JUNE 30, 2010

INDEX


		PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		3

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements	4
	Consolidated Balance Sheets As of June 30, 2010 (Unaudited) and December 31, 2009	4
	Consolidated Statements of Operations (Unaudited) for the three and six month periods ended June 30, 2010 and June 30, 2009	5
	Consolidated Statement of Changes in Owners’ Equity (Unaudited) for the six-month period ended June 30, 2010	6
	Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2010 and June 30, 2009	7
	Notes to Consolidated Financial Statements (Unaudited)	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	29
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	39
Item 4.	Controls and Procedures	40

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 6.	Exhibits	42

SIGNATURES		43

EXHIBIT INDEX		44

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

•

uncertainties regarding the economic conditions in the United States and globally;

•

domestic and global demand for oil and natural gas;

•

volatility in the prices we receive for our oil and natural gas;

•

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

•

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

•

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

•

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

•

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

•

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

•

drilling and operating risks;

•

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

•

changes in our drilling plans and related budgets;

•

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

•

uncertainties associated with our legal proceedings and their outcome; and

•

other factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the U.S. Securities and Exchange Commission.

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

Item 1.

Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except per Share Amounts)


	June 30, 2010 (unaudited)			December 31, 2009
ASSETS
Current Assets
Cash and Cash Equivalents	$	13,378		$	5,582
Accounts Receivable		8,068			14,333
Short-Term Derivative Instruments		3,943			2,124
Deferred Taxes		—			2,827
Inventory, Prepaid Expenses and Other		1,553			1,111

Total Current Assets		26,942			25,977
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		226,235			206,676
Unevaluated Oil and Gas Properties		112,876			80,218
Other Property and Equipment		41,441			25,082
Wells and Facilities in Progress		42,280			34,086
Pipelines		5,162			5,167

Total Property and Equipment		427,994			351,229
Less: Accumulated Depreciation, Depletion and Amortization		(84,884	)		(75,968	)

Net Property and Equipment		343,110			275,261
Other Assets – Net		1,975			101
Intangible Assets – Net		993			1,098
Investment in RW Gathering		4,108			840
Long-Term Derivative Instruments		3,179			1,673

Total Assets	$	380,307		$	304,950

LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	10,287		$	16,386
Accrued Expenses		9,460			9,333
Short-Term Derivative Instruments		2,108			6,692
Current Deferred Tax Liability		345			—

Total Current Liabilities		22,200			32,411
Senior Secured Line of Credit and Long-Term Debt		15,035			23,049
Long-Term Derivative Instruments		—			426
Long-Term Deferred Tax Liability		5,146			6,894
Other Deposits and Liabilities		4,504			5,830
Future Abandonment Cost		16,639			16,143

Total Liabilities	$	63,524		$	84,753
Commitments and Contingencies (See Note 11)
Owners’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 44,049,533 shares issued and outstanding on June 30, 2010 and 36,817,812 shares issued and outstanding on December 31, 2009.		44			37
Additional Paid-In Capital		373,520			292,372
Accumulated Deficit		(72,632	)		(75,555	)

Rex Energy Owners’ Equity		300,932			216,854
Noncontrolling Interests		15,851			3,343

Total Owners’ Equity		316,783			220,197

Total Liabilities and Owners’ Equity	$	380,307		$	304,950

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2010			2009			2010			2009
OPERATING REVENUE
Oil and Natural Gas Sales	$	15,530		$	11,516		$	32,048		$	20,314
Other Revenue		156			25			396			57

TOTAL OPERATING REVENUE		15,686			11,541			32,444			20,371
OPERATING EXPENSES
Production and Lease Operating Expense		5,791			5,236			11,711			10,390
General and Administrative Expense		4,573			4,392			8,735			8,143
(Gain) Loss on Disposal of Asset		(10	)		(28	)		(7	)		400
Impairment Expense		577			419			1,148			435
Exploration Expense		2,311			(247	)		3,446			835
Depreciation, Depletion, Amortization and Accretion		5,139			6,162			10,232			12,317
Other Operating Expense		333			—			566			—

TOTAL OPERATING EXPENSES		18,714			15,934			35,831			32,520
LOSS FROM OPERATIONS		(3,028	)		(4,393	)		(3,387	)		(12,149	)
OTHER INCOME (EXPENSE)
Interest Income		16			1			51			2
Interest Expense		(167	)		(190	)		(331	)		(405	)
Gain (Loss) on Derivatives, Net		4,261			(10,709	)		8,053			(5,245	)
Other Income (Expense)		(126	)		13			(159	)		(32	)

TOTAL OTHER INCOME (EXPENSE)		3,984			(10,885	)		7,614			(5,680	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		956			(15,278	)		4,227			(17,829	)
Income Tax Benefit (Expense)		(143	)		5,841			(1,424	)		7,045

INCOME (LOSS) FROM CONTINUING OPERATIONS		813			(9,437	)		2,803			(10,784	)
Income From Discontinued Operations, Net of Income Taxes		—			—			—			323

NET INCOME (LOSS)		813			(9,437	)		2,803			(10,461	)
Net Loss Attributable to Noncontrolling Interests		64			—			120			—

NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	877		$	(9,437	)	$	2,923		$	(10,461	)

Earnings per common share:
Basic – income (loss) from continuing operations attributable to Rex common shareholders	$	0.02		$	(0.26	)	$	0.07		$	(0.29	)
Basic – income from discontinued operations attributable to Rex common shareholders		—			—			—			0.01

Basic – net income (loss) attributable to Rex common shareholders	$	0.02		$	(0.26	)	$	0.07		$	(0.28	)
Basic – weighted average shares of common stock outstanding		44,028			36,846			43,082			36,789
Diluted – income (loss) from continuing operations attributable to Rex common shareholders	$	0.02		$	(0.26	)	$	0.07		$	(0.29	)
Diluted – income from discontinued operations attributable to Rex common shareholders		—			—			—			0.01

Diluted – net income (loss) attributable to Rex common shareholders	$	0.02		$	(0.26	)	$	0.07		$	(0.28	)
Diluted – weighted average shares of common stock outstanding		44,117			36,846			43,188			36,789

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN OWNERS’ EQUITY

FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 2010

(Unaudited, $ in Thousands)


	Common Stock
	Shares	Par Value		Additional Paid-In Capital		Accumulated Deficit			Total Owners’ Equity		Noncontrolling Interests
	Shares	Par Value		Additional Paid-In Capital		Accumulated Deficit			Total Owners’ Equity		Noncontrolling Interests
BALANCE December 31, 2009	36,817,812	$	37	$	292,372	$	(75,555	)	$	216,854	$	3,343
Non-cash compensation expense	—		—		961		—			961		—
Issuance of Restricted Stock, Net	331,721		—		—		—			—		—
Issuance of Common Stock, Net	6,900,000		7		80,187		—			80,194		—
Capital Contributions	—		—		—		—			—		12,628
Net Income (Loss)	—		—		—		2,923			2,923		(120	)

BALANCE June 30, 2010	44,049,533	$	44	$	373,520	$	(72,632	)	$	300,932	$	15,851

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)


	For the Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) Attributable to Rex Energy	$	2,923		$	(10,461	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Noncontrolling Interest Net Loss		(120	)		—
Non-cash Expenses		1,077			1,215
Depreciation, Depletion, Amortization and Accretion		10,232			12,752
Unrealized (Gain) Loss on Derivatives		(8,336	)		14,207
Deferred Income Tax Expense (Benefit)		1,424			(6,757	)
Impairment Expense		1,148			—
(Gain) Loss on Sale of Oil and Gas Properties		(7	)		400
Changes in operating assets and liabilities, net of effects from acquisitions
Accounts Receivable		6,267			(681	)
Inventory, Prepaid Expenses and Other Assets		(442	)		608
Accounts Payable and Accrued Expenses		(6,104	)		(6,361	)
Other Assets and Liabilities		(1,799	)		1,469

NET CASH PROVIDED BY OPERATING ACTIVITIES		6,263			6,391
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in Joint Ventures		(3,269	)		—
Proceeds from Joint Ventures		—			3,120
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		24			17,362
Acquisitions of Undeveloped Acreage		(38,581	)		(12,135	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(41,164	)		(19,370	)

NET CASH USED IN INVESTING ACTIVITIES		(82,990	)		(11,023	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debts and Lines of Credit		(23,000	)		(15,000	)
Proceeds from Long-Term Debts and Lines of Credit		15,000			15,000
Repayments of Loans and Other Notes Payable		(297	)		—
Capital Contributions by the Partners of Joint Ventures		12,628			—
Proceeds from the Issuance of Common Stock		80,520			—
Costs Incurred from the Issuance of Common Stock		(328	)		—

NET CASH PROVIDED BY FINANCING ACTIVITIES		84,523			—

NET INCREASE (DECREASE) IN CASH		7,796			(4,632	)
CASH – BEGINNING		5,582			7,046

CASH – ENDING	$	13,378		$	2,414
SUPPLEMENTAL DISCLOSURES
Interest Paid		230			664
NON-CASH ACTIVITIES
Equipment Financing		445			—

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation (the “Company”) is an independent oil and gas company with operations currently focused on the Illinois, Appalachian and Denver-Julesburg (“DJ”) Basins. In the Illinois Basin, in addition to our developmental conventional oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects. Our focus in the DJ Basin has been on acquiring acreage which we believe to be prospective for horizontal oil well drilling in the Niobrara Shale formation. In the third quarter of 2010, we intend to drill two test wells in this area. 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.

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries and variable interest entities for which we are the primary beneficiary. All material intercompany balances and transactions have been eliminated in consolidation. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together.

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

Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited consolidated and combined financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2009.

Certain prior year amounts have been reclassified to conform to the report classifications for the three and six-month periods ended June 30, 2010, with no effect on previously reported net income, net income per share, retained earnings or stockholders’ equity. Losses of approximately $0.2 million and $0.4 million for the three and six months ended June 30, 2009, respectively, have been reclassified from Interest Expense on the Statement of Operations to Gain (Loss) on Derivatives, Net. Previously, we had recorded realized settlements on our interest rate swap as interest expense. Also during the three and six-month periods ended June 30, 2009, we recorded expenses of approximately $0.4 million that have been reclassified from Depreciation, Depletion, Amortization and Accretion to Impairment Expense. During the three-month period ended March 31, 2010, we had recorded approximately $43,000 as General and Administrative expenses which we subsequently reclassified as Other Operating Expenses on our Consolidated Statements of Operations.

In the second quarter of 2009, we entered into a Participation and Exploration Agreement (the “PEA”) with Williams Production Company, LLC and Williams Production Appalachia, LLC (collectively “Williams”) that was effective as of May 5, 2009. Under the terms and conditions of the PEA, Williams may acquire, through a “drill-to-earn” structure, 50% of our working interest in certain oil and gas leases covering approximately 43,672 net acres in Centre, Clearfield and Westmoreland Counties, Pennsylvania (the “Project Area”). The PEA effectively provides that, for Williams to earn its 50% interest in the Project Area, Williams will bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled in the Project Area until such time as Williams has invested approximately $74.0 million (approximately $33.0 million on behalf of us and $41.0 million for Williams’ 50% share of the wells). In addition, Williams committed to participate in drilling a minimum of 10 horizontal wells in the Project Area to a depth sufficient to test the Marcellus Shale formation. Subject to certain termination rights, Williams agreed to fund its carry obligation prior to December 31, 2011 or make a cash payment to us for the remaining carry amount that has not been incurred at that time. Once Williams has completed its carry obligation and acquired 50% of our working interest in the leases within the Project Area, the parties will share all costs of the joint venture operations within an area of mutual interest (including the Project Area) in accordance with their participating interests, which are expected to be on a 50/50 basis. During the second quarter of 2009, we received approximately $3.1 million in expense reimbursements from Williams for certain expenditures related to geological and geophysical activities and other drilling and completion activities.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

$12.25 per share. The net proceeds from the offering were approximately $80.2 million, after deducting underwriting discounts, commissions and offering expenses. We used a portion of the proceeds of the offering to fully repay borrowings then outstanding under our Senior Credit Facility and used the remaining net proceeds to fund a portion of our capital expenditure program for 2010 and for other general corporate purposes. See also Note 9, Capital Stock, to our Consolidated Financial Statements.

2. ACQUISITIONS AND DISPOSITIONS

Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our Consolidated Statements of Operations from the closing date of acquisition. Purchase prices are allocated to the acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. Acquisitions may be funded with internal cash flow, bank borrowings or the issuance of debt and equity securities. We did not complete any acquisitions for the six-month period ending June 30, 2010. Each of the transactions listed below pertains to the leasing of large tracts of acreage and were recorded as Unevaluated Oil and Gas Properties on our Consolidated Balance Sheet.

In February 2010, R.E. Gas Development, LLC (“R.E. Gas”), our wholly owned subsidiary, acquired a 100% working interest in leases covering 2,517 gross (2,517 net) undeveloped acres in our Butler County, Pennsylvania project area. The acreage was acquired for approximately $5.7 million, or an average of $2,250 per acre.

In February 2010, R.E. Gas acquired a 100% working interest in leases covering 3,033 gross (3,033 net) undeveloped acres in Clearfield and Clinton Counties in the Commonwealth of Pennsylvania. The interest was acquired from an individual landowner for approximately $3.0 million, or $1,000 per acre. Our interest is subject to an option held by a third party, whereby the third party may elect to participate up to a 50% working interest in any well drilled. We will be accountable for a payment of an additional $1,000 per acre on 600 acres for each of the first five wells drilled on the acreage in the event that the third party elects not to participate in such wells. If the third party elects not to participate in any of the first five wells drilled on the acreage and additional payment by us is required, our total cost would be approximately $6.1 million, or $2,000 per acre.

3. FUTURE ABANDONMENT COST

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

Accretion expense during the six-month periods ended June 30, 2010 and June 30, 2009 totaled approximately $0.9 million and $0.8 million, respectively. These amounts are recorded as depreciation, depletion and amortization expense (“DD&A”) on our Consolidated Statements of Operations. In accordance with the terms of our PEA with Williams, we account for asset retirement obligations that relate to wells that are drilled jointly based on our 50% interest in those wells. We describe the details of the PEA with Williams in Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated Financial Statements.


	June 30, 2010			June 30, 2009
	($ in Thousands)			($ in Thousands)
Beginning Balance at December 31	$	16,143		$	16,283
Asset Retirement Obligation Incurred		49			183
Asset Retirement Obligation Settled		(443	)		(216	)
Asset Retirement Obligation Cancelled on Sold Well Properties		—			(1,094	)
Asset Retirement Obligation Accretion Expense		890			785

Total Asset Retirement Obligation	$	16,639		$	15,941

4. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In April 2009, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Codification (“ASC”) 805-20, which amends and clarifies ASC 805 to address application issues regarding initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. ASC 805-20 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Although we did not enter into any significant business combinations during the first six months of 2010, we believe ASC 805-20 may have a material impact on our future financial statements depending on the size and nature of any future business combinations that we may enter into. We adopted ASC 805-20 on January 1, 2010.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

In June 2009, the FASB issued ASU 2009-17, Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU 2009-17”), which was issued to improve financial reporting by enterprises involved with variable interest entities. This statement addresses the effects of certain provisions of FASB Interpretation No. 46(R) (“FIN 46(R)”) and constituent concerns about the application of certain key provisions of FIN 46(R), including those in which the accounting and disclosures do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. This statement takes effect as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim reporting periods thereafter. We adopted ASU 2009-17 as of January 1, 2010. Adoption did not have a material effect on our financial position and results of operations.

In January 2010, the FASB issued ASU 2010-01, Equity: Accounting for Distributions to Shareholders with Components of Stock and Cash (“ASU 2010-01”). The amendments to the Codification in this ASU clarify that the stock portion of a distribution to shareholders that allows them to elect to receive cash or stock with a potential limitation on the total amount of cash that all shareholders can elect to receive in the aggregate is considered a share issuance that is reflected in earnings per share prospectively and is not a stock dividend. ASU 2010-01 is effective for interim and annual periods ending on or after December 15, 2009, and should be applied on a retrospective basis. We adopted ASU 2010-01 as of January 1, 2010. Adoption did not have a material effect on our financial position and results of operations.

In January 2010, the FASB issued ASU 2010-02, Consolidation – Accounting and Reporting for Decreases in Ownership of a Subsidiary – A Scope Clarification (“ASU 2010-02”). This ASU clarifies that the scope of the decrease in ownership provisions of Subtopic 810-10 and related guidance applies to:

•

A subsidiary or group of assets that is a business or nonprofit activity;

•

A subsidiary that is a business or nonprofit activity that is transferred to an equity method investee or joint venture; and

•

An exchange of a group of assets that constitutes a business or nonprofit activity for a noncontrolling interest in an entity (including an equity method investee or joint venture).

ASU 2010-02 also clarifies that the decrease in ownership guidance in Subtopic 810-10 does not apply to: (a) sales of in substance real estate; and (b) conveyances of oil and gas mineral rights, even if these transfers involve businesses.

The amendments in this ASU expand the disclosure requirements about deconsolidation of a subsidiary or derecognition of a group of assets to include:

•

The valuation techniques used to measure the fair value of any retained investment;

•

The nature of any continuing involvement with the subsidiary or entity acquiring the group of assets; and

•

Whether the transaction that resulted in the deconsolidation or derecognition was with a related party or whether the former subsidiary or entity acquiring the assets will become a related party after the transaction.

ASU 2010-02 is effective beginning in the period that an entity adopts FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB 51 (“SFAS 160”). If an entity has previously adopted SFAS 160, the amendments are effective beginning in the first interim or annual reporting period ending on or after December 15, 2009. The amendments in ASU 2010-02 should be applied retrospectively to the first period that an entity adopts SFAS 160. We adopted SFAS 160 on January 1, 2009, and subsequently adopted ASU 2010-02 on January 1, 2010. The adoption of this ASU did not have a material effect on our financial position and results of operations.

In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements (“ASU 2010-06”). This ASU requires additional disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in ASC 820-10. The FASB’s stated objective is to improve these disclosures and, thus, increase the transparency in financial reporting. Specifically, ASU 2010-06 amends ASC 820-10 to now require:

•

A reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and

•

In the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements.

In addition, ASU 2010-06 clarifies the requirements of the following existing disclosures:

•

For purposes of reporting fair value measurement for each class of assets and liabilities, a reporting entity needs to use judgment in determining the appropriate classes of assets and liabilities; and

•

A reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. We adopted ASU 2010-06 on January 1, 2010, with no material effect on our financial position and results of operations.

In February 2010, the FASB issued ASU 2010-09, Subsequent Events: Amendments to Certain Recognition and Disclosure Requirements (“ASU 2010-09”). The amendments in this ASU define SEC filers as entities that are required to furnish its financial statements with the SEC or the appropriate agency under Section 12(i) of the Securities Exchange Act of 1934, as amended, and removes the requirement for such entities to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of GAAP. The FASB also clarified that if the financial statements have been revised, then an entity that is not an SEC filer should disclose both the date that the financial statements were issued or available to be issued and the date the revised financial statements were issued or available to be issued.

In addition, the amendments in ASU 2010-09 require an entity that is a conduit bond obligor for conduit debt securities that are traded in a public market to evaluate subsequent events through the date of issuance of its financial statements and must disclose such date. All of the amendments in ASU 2010-09 were effective upon issuance except for the use of the issued date for conduit debt obligors. This amendment is effective for interim or annual periods ending after June 15, 2010. We adopted this ASU upon its issuance with no material effect on our financial position and results of operations.

5. CONCENTRATIONS OF CREDIT RISK

At times during the six-month period ended June 30, 2010, our cash balance has exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with a high-quality counterparty. Our counterparty is an investment grade financial institution, and a lender in our senior credit facility. We have a master netting agreement in place with our counterparty that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled cash settlement date. For additional information, see Note 7, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At June 30, 2010, we carried approximately $6.1 million in production receivables, of which approximately $4.0 million were production receivables due from a single customer, Countrymark Cooperative LLP (“Countrymark”). We have a standby letter of credit from Countrymark as support for their monetary obligations to us, up to $4.0 million. During the first quarter of 2009, we placed into operation an oil offload facility in the Illinois Basin that we believe will enable us to diversify the purchasers of our oil in the future if we choose to do so. Additionally, we believe the growth in our Appalachian and DJ Basin operations will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.

6. LONG-TERM DEBT

We maintain a revolving credit facility evidenced by the Credit Agreement, dated September 28, 2007, with KeyBank National Association as Administrative Agent; Royal Bank of Canada, as Syndication Agent; Sovereign Bank, as Documentation Agent; and lenders from time to time parties thereto (as amended from time to time, the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. As of June 30, 2010, the borrowing base under the Senior Credit Facility was $100 million; however, the revolving credit facility may be increased up to $200 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. The borrowing base is re-determined by the bank group semi-annually, with the next review scheduled for October 2010. Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months.

Borrowings under the Senior Credit Facility bear interest, at our election, at the Adjusted LIBOR or the Alternative Base Rate (as defined below) plus, in each case an applicable per annum margin. The applicable per annum margin is determined based upon our total borrowing base utilization percentage in accordance with a pricing grid. The applicable per annum margin ranges from 1.75% to 2.5% for Eurodollar loans and .5% to 1.25% for ABR loans. The Adjusted Base Rate is equal to the greater of: (i) KeyBank’s announced prime rate; (ii) the federal funds effective rate from time to time plus ¹/2 of 1%; and (iii) LIBO Rate plus 1.25%. Our commitment fee is also dependent on our total borrowing base utilization percentage and is determined based upon an applicable per annum margin which ranges from .375% to .50%.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20.0 million and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate. For further information on our derivative instruments, see Note 7, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.

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

The Senior Credit Facility also requires that we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of its financial statements, such as our commercial bank lenders. The covenant states that as of the last day of any fiscal quarter, our ratio of consolidated current assets as of such day to consolidated current liabilities as of such day is to be less than 1.0 to 1.0. Additionally, the covenant states that as of the last day of any fiscal quarter, our ratio of EBITDAX for the period of four fiscal quarters ending on such day to interest expense for such period is to be less than 3.0 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the period of four fiscal quarters ending on such day is not to exceed 4.0 to 1.0. As of June 30, 2010, we were in compliance with all of our debt covenants.

In addition to our Senior Credit Facility, we may, from time to time in the normal course of business, finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and lines of credit consisted of the following at June 30, 2010 and December 31, 2009.


	June 30, 2010			December 31, 2009
	($ in Thousands)			($ in Thousands)
Senior Credit Facility¹	$	15,000		$	23,000
Other Loans and Notes Payable		514			366

Total Debts		15,514			23,366
Less Current Portion of Long-Term Debt		(479	)		(317	)

Total Long-Term Debts	$	15,035		$	23,049

The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans. The average interest rate on borrowings under our Senior Credit Facility for the six months ended June 30, 2010 was approximately 2.1%. The average interest rate on our Other Loans and Notes Payable is approximately 2.3%.

7. FAIR VALUE OF FINANCIAL AND DERIVATIVE INSTRUMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we enter into oil and natural gas commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparty. We do not enter into these arrangements for speculative trading purposes. As of June 30, 2010, our oil and natural gas derivative commodity instruments consisted of fixed rate swap contracts and collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as other income or expense under the heading Gain (Loss) on Derivatives, Net.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

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

We enter into the majority of our derivative arrangements with one counterparty and have a netting agreement in place. We present our derivatives as gross assets or liabilities on our Consolidated Balance Sheet. We do not obtain collateral to support the derivative agreements, but monitor the financial viability of our counterparties and believe our credit risk is minimal on these transactions. For additional information on the credit risk with regards to our counterparty, see Note 5, Concentrations of Credit Risk, to our Consolidated Financial Statements.

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

We received net payments of $0.3 million and $0.1 million under these commodity derivative instruments during the three and six-month periods ended June 30, 2010, respectively. We received net payments of approximately $1.5 million and $9.9 million under these commodity derivative instruments during three and six-month periods ended June 30, 2009, respectively. Payments received during the six months ended June 30, 2009 included approximately $4.6 million attributable to the early settlement of certain 2011 oil hedges. Unrealized gains associated with our commodity derivative instruments from continuing operations amounted to $3.9 million and $8.0 million for the three and six-month periods ended June 30, 2010, respectively. Unrealized losses associated with our commodity derivative instruments from continuing operations amounted to $12.2 million and $15.0 million for the three and six-month periods ended June 30, 2009, respectively.

The following table summarizes the location and amounts of gains and losses on derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six-month periods ended June 30, 2010 and 2009 ($ in thousands):


	Three Months Ended June 30, 2010									Three Months Ended June 30, 2009
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total			Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	—		$	1,599		$	1,599		$	—		$	(1,629	)	$	(1,629	)
Mark-to-market fair value adjustments		—			3,819			3,819			—			(9,818	)		(9,818	)
Settlement of contracts ^(a)		(864	)		—			(864	)		720			—			720

Crude Oil Total		(864	)		5,418			4,554			720			(11,447	)		(10,727	)

*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			(1,063	)		(1,063	)		—			(626	)		(626	)
Mark-to-market fair value adjustments		—			(447	)		(447	)		—			(154	)		(154	)
Settlement of contracts ^(a)		1,208			—			1,208			824			—			824

Natural Gas Total		1,208			(1,510	)		(302	)		824			(780	)		44

*Interest Rate*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			210			210			—			168			168
Mark-to-market fair value adjustments		—			(6	)		(6	)		—			(5	)		(5	)
Settlement of contracts ^(a)		(195	)		—			(195	)		(189	)		—			(189	)

Interest Rate Total		(195	)		204			9			(189	)		163			(26	)

Gain (Loss) on Derivatives, Net	$	149		$	4,112		$	4,261		$	1,355		$	(12,064	)	$	(10,709	)

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

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)


	Six Months Ended June 30, 2010									Six Months Ended June 30, 2009
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total			Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	—		$	2,891		$	2,891		$	—		$	(3,531	)	$	(3,531	)
Mark-to-market fair value adjustments		—			3,636			3,636			—			(12,661	)		(12,661	)
Settlement of contracts ^(a)		(1,698	)		—			(1,698	)		8,555			—			8,555

Crude Oil Total		(1,698	)		6,527			4,829			8,555			(16,192	)		(7,637	)

*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			(962	)		(962	)		—			(546	)		(546	)
Mark-to-market fair value adjustments		—			2,414			2,414			—			1,758			1,758
Settlement of contracts ^(a)		1,807			—			1,807			1,333			—			1,333

Natural Gas Total		1,807			1,452			3,259			1,333			1,212			2,545

*Interest Rate*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			389			389			—			352			352
Mark-to-market fair value adjustments		—			(33	)		(33	)		—			(136	)		(136	)
Settlement of contracts ^(a)		(391	)		—			(391	)		(369	)		—			(369	)

Interest Rate Total		(391	)		356			(35	)		(369	)		216			(153	)

Gain (Loss) on Derivatives, Net	$	(282	)	$	8,335		$	8,053		$	9,519		$	(14,764	)	$	(5,245	)

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

As of June 30, 2010, we had entered into an interest rate swap derivative instrument which hedged our interest rate risk associated with changes in LIBOR on $20.0 million of notional value. We use the interest rate swap agreement to manage the risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. Under our interest rate swap agreement, we agree to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount. The interest rate under the swap is 4.15% and the agreement expires in November 2010. The fair value of the swap at June 30, 2010 was a liability of $0.4 million, a decrease of $0.4 million for the six-month period ended June 30, 2010, based on current LIBOR quotes. We have accounted for the interest rate swap by recording the unrealized and realized gains for the three and six months ended June 30, 2010 and 2009 in Gain (Loss) on Derivatives, Net on our Consolidated Statements of Operations.

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at its fair value. The fair value associated with our derivative instruments from continuing operations was an asset of approximately $5.0 million and a liability of $3.3 million at June 30, 2010 and December 31, 2009, respectively. The fair value is based on the valuation methodologies of our counterparties and third-party valuation providers. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2010 consisted of:


Period	Contract Type	Volume	Average Derivative Price	Fair Market Value ($ in Thousands)
Oil
2010	Swap	90,000 Bbls	$62.20	$	(1,305	)
2010	Collar	204,000 Bbls	$62.94 - $86.85	$	(333	)
2011	Collar	408,000 Bbls	$67.94 - $107.31	$	1,235
2012	Collar	192,000 Bbls	$66.25 - $125.66	$	752

	Total	894,000 Bbls		$	349

Natural Gas
2010	Swap	60,000 Mcf	$6.00	$	71
2010	Put	540,000 Mcf	$6.31	$	858
2010	Collar	720,000 Mcf	$5.98 - $8.35	$	938
2011	Collar	1,800,000 Mcf	$5.27 - $7.05	$	732
2011	Put	720,000 Mcf	$8.00	$	1,957
2012	Collar	1,200,000 Mcf	$5.78 - $6.91	$	465

	Total	5,040,000 Mcf		$	5,021

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009 is summarized below ($ in thousands).


	June 30, 2010			December 31, 2009
Short-Term Derivative Assets:
Crude Oil – Collars	$	732		$	178
Natural Gas – Swaps		71			25
Natural Gas – Collars		1,303			1,921
Natural Gas – Puts		1,837			—

Total Short –Term Derivative Assets	$	3,943		$	2,124

Long-Term Derivative Assets:
Crude Oil – Collars	$	1,370		$	9
Natural Gas – Collars		830			1,664
Natural Gas – Puts		979			—

Total Long – Term Derivative Assets	$	3,179		$	1,673

Total Derivative Assets	$	7,122		$	3,797

Short-Term Derivative Liabilities:
Crude Oil – Swaps	$	(1,305	)	$	(3,615	)
Crude Oil – Collars		(447	)		(2,346	)
Natural Gas – Collars		—			(20	)
Interest Rate – Swap		(356	)		(711	)

Total Short – Term Derivative Liabilities	$	(2,108	)	$	(6,692	)

Long-Term Derivative Liabilities:
Crude Oil – Collars	$	—		$	(405	)
Natural Gas – Collars		—			(21	)

Total Long – Term Derivative Liabilities	$	—		$	(426	)

Total Derivative Liabilities	$	(2,108	)	$	(7,118	)

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. There are three levels of fair value hierarchy

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

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

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

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

During the six-month period ended June 30, 2010, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value ($ in thousands):


				Fair Value Measurements at June 30, 2010 Using:
	Total Carrying Value as of June 30, 2010			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivatives^(a) – commodity swaps and collars	$	5,370		$	—	$	5,370		$	—
– interest rate swaps	$	(356	)	$	—	$	(356	)	$	—
Asset Retirement Obligations	$	(16,639	)	$	—	$	—		$	(16,639	)

(a)	All of our derivatives are classified as Level 2 measurements. For information regarding their classification on our Consolidated Balance Sheets, please refer to the table on page 15 of this report.

Our derivative commodity swaps and collars and interest rate swaps are valued by third parties using valuation models that are primarily industry-standard models that consider various inputs including: quoted forward prices; time value; volatility factors; and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative commodity swaps and collars and interest rate swaps are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

Asset Retirement Obligations

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; estimated probabilities, amounts and timing of settlements; fixed and variable plugging costs; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. Refer to Note 3, Future Abandonment Cost, of our Consolidated Financial Statements for further information on asset retirement obligations, which include a reconciliation of the beginning and ending balances which represent the entirety of our Level 3 fair value measurements.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

8. INCOME TAXES

We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Income Tax Expense (Benefit)	$	143		$	(5,841	)	$	1,424		$	(7,045	)
Effective Tax Rate		15.0	%		38.2	%		33.7	%		39.5	%

For the three and six months ended June 30, 2010, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to an adjustment to the tax basis as it relates to certain non-controlling interest components. For the three and six months ended June 30, 2009, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily to state income taxes and other permanent differences.

No income tax payments were made during the three and six month periods ending June 30, 2010, or the comparable periods in 2009.

9. CAPITAL STOCK

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2010 and December 31, 2009, we had 44,049,533 and 36,817,812 shares of common stock outstanding, respectively.

On January 21, 2010, we completed an underwritten public offering of 6,900,000 shares of our common stock, which included 900,000 shares of common stock issued upon the full exercise of the underwriters’ over-allotment option, at a public offering price of $12.25 per share. The net proceeds from the offering were approximately $80.2 million, after deducting underwriting discounts, commissions and offering expenses. We used a portion of the proceeds of the offering to fully repay outstanding borrowings under our Senior Credit Facility and used the remaining net proceeds to fund a portion of our capital expenditure program for 2010 and for other general corporate purposes.

10. EMPLOYEE BENEFIT AND EQUITY PLANS

401(k) Plan

We sponsor a 401(k) plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our matching contributions to the plan are discretionary and we ceased to provide a matching contribution to the 401(k) plan beginning in January 2009. During June 2009, our management made the decision to resume our matching contributions to the 401(k) plan beginning in July 2009. Our contributions to the plan were $84,000 and $0.1 million for the three and six-month periods ended June 30, 2010, respectively, and $40,000 and $50,000 for the same periods in 2009, respectively.

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. Although we have not yet recognized any tax benefits, we would report any benefits of tax deductions in excess of recognized compensation as a financing cash flow, rather than as an operating cash flow.

2007 Long-Term Incentive Plan

We have granted stock options, stock appreciation rights and restricted stock awards to various employees and non-employee directors under the terms of our 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our Board of Directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are: selecting participants to receive awards; determining the form, amount and other terms and conditions of awards; interpreting the provisions of the Plan or any award agreement; and adopting such rules, forms, instruments and guidelines for administering the Plan

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees, are intended to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.

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

Stock Options

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

During the six-month period ended June 30, 2010, the Compensation Committee awarded nonqualified options to purchase a total of 36,935 shares of our common stock to our five non-employee directors. The nonqualified stock options granted to our non-employee directors have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of grant, and vest and become exercisable in one-third increments on the first, second and third year anniversaries of the date of grant. All options will vest and become immediately exercisable upon a “change in control” of us, as such term is defined in the Plan.

A summary of the stock option activity is as follows:


	Shares		Weighted Average Exercise Price
Outstanding on December 31, 2009	873,837		$	13.41
Granted	36,935			10.42
Exercised	—			—
Forfeited	(28,500	)		7.46

Outstanding on June 30, 2010	882,272		$	13.48

Stock-based compensation expense relating to stock options for the three and six-month periods ended June 30, 2010 totaled $0.3 million and $0.7 million, respectively, compared to $0.5 million and $1.8 million for the same periods in 2009. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

A summary of the status of our issued and outstanding stock options as of June 30, 2010 is as follows:


	Outstanding				Exercisable
Exercise Price	Number Outstanding At 6/30/10	Weighted-Average Remaining Contractual Life (Years)	Weighted-Average Exercise Price		Number Exercisable At 6/30/10	Weighted-Average Exercise Price
$ 9.99	363,749	7.35	$	9.99	58,749	$	9.99
$ 9.50	125,000	7.35	$	9.50	83,334		9.50
$13.56	33,200	7.64	$	13.56	—		—
$22.34	50,000	7.79	$	22.34	12,000		22.34
$23.00	75,000	7.84	$	23.00	—		—
$23.88	75,000	7.88	$	23.88	—		—
$23.28	6,000	3.02	$	23.28	—		—
$19.92	26,000	3.12	$	19.92	—		—
$21.10	30,000	3.15	$	21.10	—		—
$ 5.04	61,388	8.85	$	5.04	20,464		5.04
$10.42	36,935	9.98	$	10.42	—		—

Total	882,272	7.39	$	13.48	174,547	$	10.02

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at June 30, 2010 were 7.39 years and $0.4 million, respectively. As of June 30, 2010, unrecognized compensation expense related to stock options totaled approximately $1.2 million, which will be recognized over a weighted average period of 0.74 years.

Stock Appreciation Rights

Stock appreciation rights (“SARs”) represent the right to receive cash or shares of common stock in the future equivalent to the difference between the fair market value at the time of exercise and the exercise price. As of June 30, 2010, we had 73,500 SARs outstanding, which have an exercise price of $13.56, the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable on the third anniversary of the grant date, provided that the holder remains our employee until that date. The SARs also provide that all unvested SARs vest and become immediately exercisable upon a “change in control” of us, as such term is defined in the Plan. The outstanding SARs issued may only be exercised for cash settlement. Compensation expense relating to SARs for the three and six-month periods ended June 30, 2010 totaled credits of $22,000 and $6,000, respectively, compared with expense of $60,000 and $68,000 for the same periods in 2009. The expense related to SARs was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense.


	Outstanding						Exercisable
Strike Price	Number of SARs Granted	SARs Forfeited or Cancelled	SARs Outstanding	Weighted-Average Remaining Contractual Life (Years)	Weighted-Average Strike Price		SARs	Weighted-Average Exercise Price
$ 13.56	109,500	36,000	73,500	7.64	$	13.56	—	—

Total	109,500	36,000	73,500	7.64	$	13.56	—	—

Restricted Stock Awards

During the six-month period ended June 30, 2010, the Compensation Committee issued 349,307 shares of restricted common stock to 18 employees. The shares granted under these awards are subject to time vesting and performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse with respect to the greater of: (i) 50% of the maximum number of shares or (ii) the number of shares that would be awarded if the applicable performance-based goals and the extent such goals were satisfied are measured as of the date of the change in control. Shares that do not become vested, as defined in the Plan, will be forfeited and the recipient will cease to have any rights of a stockholder with respect to such forfeited shares.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Compensation expense associated with restricted stock awards is recognized on a straight-line basis over the vesting period and is periodically adjusted for estimated forfeiture rates and estimated satisfaction of performance-based goals. Compensation expense associated with restricted stock awards totaled $0.2 million and $0.3 million for the three and six-month periods ended June 30, 2010, respectively, compared to $0.1 million for the same periods in 2009. As of June 30, 2010, total unrecognized compensation cost related to restricted common stock grants was approximately $2.1 million.

A summary of the restricted stock activity for the six months ended June 30, 2010 is as follows:


	Number of Shares		Weighted Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2009	248,100		$	3.74
Awards	349,307			11.49
Forfeitures	(17,586	)		6.95
Restrictions released	—			—

Restricted stock awards, as of June 30, 2010	579,821		$	8.31

11. COMMITMENTS AND CONTINGENCIES

Legal Reserves

Our reserve for legal accruals relating to legal costs and expenses associated with various legal matters and proceedings totaled approximately $0.4 million and $1.4 million as of June 30, 2010, and December 31, 2009, respectively. The accrual of reserves for legal matters is included in Accrued Expenses on the Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, it is reasonably possible that we could incur an additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on our consolidated financial position or results of operations, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred. For additional information, see Note 18, Litigation, to our Consolidated Financial Statements.

Drilling and Development

At June 30, 2010, we had one drilling commitment in our Appalachian Basin. The commitment requires us, by April 2014, to drill five natural gas wells and complete one natural gas well, which have already been started. We estimate an average investment in each well to be $1.0 million for a total drilling commitment of approximately $5.0 million.

Leasing

At June 30, 2010, we had three installment payment commitments on mineral interests that were previously leased. The first commitment provides that we pay $350 per mineral acre for 5,722 acres, or a total commitment of $2.0 million, in 2012. The second commitment requires that we pay $250 per mineral acre for 5,761 acres, or $1.4 million, in each of the next two years for a total commitment of $2.8 million. The third commitment requires that we pay $350 per mineral acre for 762 acres, or $0.3 million, in each of the next three years for a total commitment of $0.8 million. We have recorded $1.7 million as a short-term liability in Accrued Expenses on our Consolidated Balance Sheets. The long-term portion of these payments was recorded in Other Deposits and Liabilities on our Consolidated Balance Sheets.

Environmental

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

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except for contingent liabilities associated with the enforcement action initiated by the U.S. EPA and the class action litigation filed in the U.S. District Court of the Southern District of Illinois relating to alleged H₂ S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Contract Wells

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

Letters of Credit

At June 30, 2010, we had posted $0.8 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

At June 30, 2010, we had lease commitments for three different office locations. Rent expense has been recorded in General and Administrative expense on our Consolidated Statements of Operations for continued operations as a credit of $0.2 million and expense of $0.2 million for the three and six-month periods ended June 30, 2010, respectively, compared to $0.1 million and $0.2 million for the same periods in 2009, respectively. During the first quarter of 2010 we closed our Canonsburg, Pennsylvania office and subsequently recognized, as Rent expense, the present value of all future lease payments, which approximated $0.3 million. During the second quarter of 2010 we subleased our Canonsburg office location and recognized a credit to Rent Expense of approximately $0.3 million. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):


2010	$	286
2011		559
2012		560
2013		505
2014		—
Thereafter		—

Total	$	1,910

Capacity Reservation

In relation to our formation of Keystone Midstream Services, LLC (“Keystone Midstream”) (see Note 14, Variable Interest Entities, to our Consolidated Financial Statements), we entered into a capacity reservation arrangement with Keystone Midstream to ensure sufficient capacity at the cryogenic gas processing plant owned by Keystone Midstream to process our produced natural gas. Under the terms of the arrangement, we have reserved 20 Mmcfe of processing capacity per day for the first year of operation and 40 Mmcfe of processing capacity for the subsequent nine years of operation. If we do not meet our capacity reservation volumes, we are obligated to pay $0.30/Mcfe per day for the difference between actual processed volumes and the reservation volume. In the event that we do not process any gas through the cryogenic gas processing plant we may be obligated to pay approximately $2.2 million for the first year of operation and approximately $4.4 million for each of the following nine years. As of June 30, 2010, management believes that the probability of incurring these liabilities is remote and, thus, no provision has been recorded.

Other

In addition to the Asset Retirement Obligation discussed in Note 3, Future Abandonment Costs, to our Consolidated Financial Statements, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. These amounts total $0.3 million at June 30, 2010 and December 31, 2009 and are included in Other Liabilities on our Consolidated Balance Sheets.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

12. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

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

As of December 31, 2009, we did not retain any assets that were required to be classified as Assets Held for Sale on our Consolidated Balance Sheet. The results of operations for these properties are reflected in discontinued operations on our Consolidated Statements of Operations. As of June 30, 2010, we did not record any results from discontinued operations. As of June 30, 2009, we recorded a loss on sale of assets of approximately $0.4 million in our Consolidated Statement of Operations. Upon closing of the sale, we recorded severance wages in discontinued operations of approximately $0.2 million for our former employees in our Southwest Region. Summarized financial information for discontinued operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the discontinued operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.


	For the Three Months Ended June 30, ($ in Thousands, Except per Share Data)				For the Six Months Ended June 30, ($ in Thousands, Except per Share Data)
	2010		2009		2010		2009
Revenues:
Oil and Natural Gas Sales	$	—	$	—	$	—	$	193
Other Revenue		—		—		—		—

Total Operating Revenue		—		—		—		193

Costs and Expenses:
Production and Lease Operating Expense		—		—		—		237
General and Administrative Expense (Income)		—		—		—		(97	)
Gain on Derivatives		—		—		—		(558	)

Total Costs and Expenses		—		—		—		(418	)

Income from Discontinued Operations Before Income Tax								611
Income Tax Expense		—		—		—		288

Income from Discontinued Operations, Net of Taxes	$	—	$	—	$	—	$	323

Earnings per Common Share:
Basic and Diluted Income		—		—	$	—	$	0.01
Production:
Crude Oil (Bbls)		—		—		—		7,507
Natural Gas (Mcf)		—		—		—		61,661

Total (Mcfe)		—		—		—		106,703

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

13. EARNINGS PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period. Diluted income per common share includes the speculative exercise of stock options and SARs, given that the hypothetical effect is not anti-dilutive. Stock options of 792,844 and SARs of 73,500 for the three months ended June 30, 2010 and stock options of 776,889 and SARs of 73,500 for the six months ended June 30, 2010 were outstanding but not included in the computations of diluted net income per share because the grant prices were greater than the average market price of the common shares. Due to our net loss from continuing operations for the three and six months ended June 30, 2009, we excluded all 938,837 outstanding stock options and 73,500 SARs because the effect would have been anti-dilutive to the computations. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):


	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
Numerator:
Net Income (Loss) From Continuing Operations	$	877	$	(9,437	)	$	2,923	$	(10,784	)
Net Income From Discontinued Operations		—		—			—		323

Net Income (Loss)		877		(9,437	)		2,923		(10,461	)

Denominator:
Weighted Average Common Shares Outstanding - Basic		44,028		36,846			43,082		36,789
Effect of Dilutive Securities:
Employee Stock Options and SARs		89		—			106		—

Weighted Average Common Shares Outstanding - Diluted		44,117		36,846			43,188		36,789


Earnings per Common Share:
Basic — Net Income (Loss) From Continuing Operations	$	0.02	$	(0.26	)	$	0.07	$	(0.29	)
— Net Income From Discontinued Operations		—		—			—		0.01

— Net Income (Loss)	$	0.02	$	(0.26	)	$	0.07	$	(0.28	)

Diluted — Net Income (Loss) From Continuing Operations	$	0.02	$	(0.26	)	$	0.07	$	(0.29	)
— Net Income From Discontinued Operations		—		—			—		0.01

— Net Income (Loss)	$	0.02	$	(0.26	)	$	0.07	$	(0.28	)

14. VARIABLE INTEREST ENTITIES

Water Solutions Holdings, LLC

On November 12, 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions Holdings”) for the purpose of acquiring, managing and operating water treatment, water disposal, water sales, and water transportation facilities that are designed to treat, dispose or transport brine and other waste waters produced in oil and gas well development activities. The members of Water Solutions Holdings are Rex Energy Corporation, which owns an 80% membership interest, and Sand Hills, which owns a 20% membership interest and serves as the operator of the entity. Water Solutions Holdings and its wholly owned subsidiary, Keystone Clearwater Solutions, LLC (“Keystone Clearwater”), began water treatment and water sales activities in January 2010 and are primarily serving third parties, however Water Solutions Holdings and Keystone Clearwater have, and will continue to, serve our wells on a periodic basis.

We have identified Water Solutions Holdings as a variable interest entity (“VIE”) due to the lack of sufficient equity at risk to permit the entity to finance its activities without additional subordinated financial support. As the 80% interest owner in this entity, we have the obligation to absorb a majority of the losses, which could potentially be significant to the entity, as well as the right to receive benefits, which could potentially be significant. Additionally, we have the ability to direct the activities of the entity that most significantly impact the entity’s economic performance through our voting rights on the board of directors. Based on these factors, we have concluded that we hold a controlling financial interest in Water Solutions Holdings and are thus considered the primary beneficiary. As primary beneficiary, we fully consolidated the accounts of Water Solutions Holdings in our financial statements and accounted for the equity interest owned by Sand Hills as a noncontrolling interest. As of June 30, 2010, no creditors have provided financing to Water Solutions Holdings; therefore there is no recourse to our general credit.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

During the six months ended June 30, 2010, we contributed approximately $0.7 million to fund the operations of Water Solutions Holdings. As of June 30, 2010, the carrying amount and classification of Water Solutions Holdings assets and liabilities as consolidated into our financial statements were as follows, with no restrictions or obligations to use certain assets to settle associated liabilities (Water Solutions Holdings did not exist as of June 30, 2009):


	June 30, 2010 (in thousands)
ASSETS
Cash and Cash Equivalents	$	144
Accounts Receivable		142
Inventory, Prepaid Expenses and Other		8
Other Property and Equipment		522
Wells and Facilities in Progress		665
Less: Accumulated Depreciation, Depletion and Amortization		(45	)
Intangible Assets – Net		32

Total Assets	$	1,468
LIABILITIES
Accounts Payable	$	71
Accrued Expenses		30

Total Liabilities	$	101

Keystone Midstream Services, LLC

On December 21, 2009, our wholly owned subsidiary, R.E. Gas, and Stonehenge Energy Resources, L.P. (“Stonehenge”) formed Keystone Midstream Services, LLC (“Keystone Midstream”), a midstream joint venture focused on building, operating and owning a high pressure gathering system and cryogenic gas processing plant in Butler County, Pennsylvania. R.E. Gas owns a 40% membership interest in Keystone Midstream and the remaining 60% membership interest is owned by Stonehenge, which also serves as the operator of the entity. We will serve as the primary customer to the cryogenic gas processing plant and will pay a fee to Keystone Midstream based on the amount of gas and NGL sales processed.

We have identified Keystone Midstream to be a VIE because the holders of the equity at risk are protected from the first dollar risk of loss associated with one of the predominant risks of the entity through the pricing terms of a leasing arrangement with us. In accordance with the leasing agreement, R.E. Gas would be responsible for a reservation fee of $0.30 per Mcf per day of capacity for any volumes processed less than 20 MMcf per day for the first year and volumes less than 40 MMcf per day thereafter. As a result of the capacity reservation fee, Stonehenge will continue to recuperate its capital contribution regardless of the quantities of gas processed. For additional information on the capacity reservation fee, see Note 11, Commitments and Contingencies, to our Consolidated Financial Statements.

The processing and sale of natural gas and natural gas liquids is identified as the activity that most significantly impacts Keystone Midstream’s economic performance. As of June 30, 2010, we were the sole producer committed to process our gas with Keystone Midstream and, thus, have the power to direct the activities of the entity that most significantly impact its economic performance through the volumes of gas that we produce. In addition, we are obligated to absorb the majority of the losses of the entity primarily through the capacity reservation fee described above. Based on these factors, it was determined that we hold a controlling financial interest in Keystone Midstream and are considered the primary beneficiary. As the primary beneficiary, we fully consolidated the accounts of Keystone Midstream in our financial statements and accounted for the equity interest owned by Stonehenge as a noncontrolling interest. As of June 30, 2010, no creditors have provided financing to Keystone Midstream; therefore there is no recourse to our general credit.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

During the six months ended June 30, 2010, we contributed approximately $7.9 million to fund the operations of Keystone Midstream. As of June 30, 2010, the carrying amount and classification of Keystone Midstream assets and liabilities as consolidated into our financial statements were as follows, with no restrictions or obligations to use certain assets to settle associated liabilities (Keystone Midstream did not exist as of June 30, 2009):


	June 30, 2010 (in thousands)
ASSETS
Cash and Cash Equivalents	$	9,758
Accounts Receivable		3,444
Inventory, Prepaid Expenses and Other		17
Wells and Facilities in Progress		12,056
Pipelines		1,748
Less: Accumulated Depreciation, Depletion and Amortization		(91	)

Total Assets	$	26,932
LIABILITIES
Accounts Payable	$	969
Accrued Expenses		1
Total Liabilities	$	970

15. RELATED PARTY

RW Gathering, LLC

Pursuant to the terms of our PEA with Williams, we and Williams agreed to form RW Gathering, LLC (“RW Gathering”), a Delaware limited liability company, to own any gas-gathering assets which we agreed to jointly construct in order to facilitate the development of our Project Area (for additional information see Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated Financial Statements). The initial members of RW Gathering are Williams Production Appalachia, LLC and R.E. Gas Development, LLC, our wholly owned subsidiary, with each party owning an equal interest in the company. On January 1, 2010, Williams Production Appalachia, LLC became the manager of RW Gathering. We account for our interest in RW Gathering via the equity method. Under the equity method, we recorded our investment in RW Gathering of approximately $4.1 million on our Consolidated Balance Sheet as Investment in RW Gathering. During the first six months of 2010, we contributed approximately $3.3 million in cash to RW Gathering to support current pipeline and gathering line construction. RW Gathering recorded net losses from continuing operations of $32,000 and $34,000 for the three and six-month periods ended June 30, 2010, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and DD&A expense. Our share of the net loss from continuing operations is recorded on the Statement of Operations as Other Expense. For the three and six months ended June 30, 2010, we incurred approximately $57,000 and $0.1 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of June 30, 2010, there were no receivables or payables in relation to RW Gathering due to or from us. There were no operations for RW Gathering as of June 30, 2009.

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

16. SUSPENDED EXPLORATORY WELL COSTS

We capitalize the costs of exploratory wells if the wells find sufficient quantities of reserves to justify their completion as producing wells or we are making sufficient progress towards assessing the reserves and the economic and operating viability of the projects.

The following table reflects the net change in capitalized exploratory well costs for the six months ended June 30, 2010 and the year ended December 31, 2009 ($ in thousands):


	June 30, 2010			December 31, 2009
Beginning Balance at January 1,	$	7,846		$	3,716
Additions to capitalized exploratory well costs pending the determination of proved reserves		24,706			4,130
Divested Wells		—			—
Reclassification of wells, facilities, and equipment based on the determination of proved reserves		(9,632	)		—
Capitalized exploratory well costs charged to expense		—			—

Ending Balance at end of period		22,920			7,846
Less exploratory well costs that have been capitalized for a period of one year or less		(17,666	)		(4,130	)

Capitalized exploratory well costs for a period of greater than one year	$	5,254		$	3,716
Number of projects that have exploratory well costs capitalized for a period of more than one year		3			3

The $5.3 million in well costs that have been capitalized for a period of greater than one year relate to three projects, one in our Illinois Basin and two in our Appalachian Basin. The costs related to our Illinois Basin are for our Lawrence Field ASP Flood project and were incurred beginning in 2007. Proved reserve quantities for tertiary recovery projects, such as the ASP project, typically take a longer period of time to evaluate than conventional operations due to their capital intensive nature and longer lead time of producing results. We are continuously undergoing an analysis of various stimulation techniques, with the assistance of an outside third-party consultant, to determine if economic quantities of crude oil can be produced from this project. It is anticipated that we will commence ASP chemical injection during the third quarter of 2010, at which time an additional eight to 12 months will be needed to evaluate any proved reserves. The projects in the Appalachian Basin relate to two wells which have been drilled, or are in the process of being drilled, in our Clearfield County, Pennsylvania project area for which costs were incurred beginning in 2008. The first of these wells has been drilled, but is not yet active, due to the lack of a current sales outlet. This well is continuously tested and monitored and has displayed, in our opinion, the ability to produce economic quantities of natural gas when a sales outlet is in place. The second well, which is in close proximity of the first well, has not yet been completed due to the lack of a current sales outlet. However, it is believed that when this well is completed it will perform similar to the first well and be capable of producing economic quantities once a sales outlet is in place. We do intend to continue to drill wells in this area, at which time we intend to construct a sales outlet and complete and activate our two previously discussed wells.

17. INTANGIBLE ASSETS

Our intangible assets are primarily comprised of sales agreements and we amortize our intangible assets on the straight-line method over their respective estimated lives, which is, on average, five years. We amortize any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable, using the straight-line method. Amortization expense for our intangible assets was $0.1 million and $0.2 million for the three and six-month periods ended June 30, 2010, respectively, and $0.1 million and $0.2 million for the three and six-month periods ended June 30, 2009, respectively. The aggregate estimated annual amortization expense for the remainder of 2010, and for each of the next five calendar years is as follows: 2010 – $0.2 million; 2011 – $0.4 million; 2012 – $0.3 million; 2013 – $0 ; 2014 – $0; and 2015 – $0.

The following is a summary of intangible assets at the dates indicated (in thousands):


	June 30, 2010			December 31, 2009
Intangible Assets – Gross	$	2,221		$	2,107
Accumulated Amortization		(1,228	)		(1,009	)

Intangible Assets – Net	$	993		$	1,098

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

18. LITIGATION

PennTex Illinois and Rex Operating — Settlement Agreement — H₂S Class Action Litigation

Our wholly owned subsidiaries, PennTex Resources Illinois, Inc. (“PennTex Illinois”) and Rex Energy Operating Corp. (“Rex Operating”), were defendants in a class action lawsuit filed in the United States District Court for the Southern District of Illinois. The action was commenced on October 17, 2006, by plaintiffs Julia Leib (“Leib”) and Lisa Thompson (“Thompson”), individually and as putative class representatives on behalf of all persons and non-governmental entities that owned property or resided on property located in the towns of Bridgeport and Petrolia, Illinois. The complaint contained several causes of action and generally asserted that the operation of oil wells that are controlled, owned or operated by PennTex Illinois and Rex Operating had resulted in contamination of the class area with hydrogen sulfide. The district court certified the lawsuit as a class action on February 26, 2009.

On December 17, 2009, PennTex Illinois and Rex Operating entered into a Settlement Agreement and Release (the “Settlement Agreement”) with Leib and Thompson, individually and on behalf of the certified class, to settle a class action lawsuit. Under the terms of the Settlement Agreement, PennTex Illinois and Rex Operating, without any admission of liability, agreed to pay the class a total of $1.9 million, of which Leib and Thompson would each receive $25,000. PennTex Illinois and Rex Operating also agreed to permanently plug four inactive oil wells adjacent to the residences of Leib and Thompson. Pursuant to the terms of the Settlement Agreement, in return for the above consideration, each member of the class, including Leib and Thompson, released all claims against PennTex Illinois and Rex Operating and their affiliates that in any way related to hydrogen sulfide or other environmental conditions in the class area which were the subject of, or could have been the subject of, the claims alleged in the class action lawsuit. In addition, each class member released any claims related to any future releases of hydrogen sulfide in the class area on the condition that PennTex Illinois and Rex Operating substantially comply with the terms and conditions of the consent decree previously entered into by the companies with the U.S. Environmental Protection Agency and the U.S. Department of Justice on September 7, 2006. Leib and Thompson also agreed to release any individual claims they may have had for medical monitoring. The Settlement Agreement did not provide for a release of any potential individual claims of other class members since those claims were not the subject of the class action lawsuit.

The Settlement Agreement was conditioned upon the entry of an order of the district court granting preliminary approval of the settlement, which was issued by the district court on December 21, 2009. The Settlement Agreement was also conditioned upon the entry of an order by the district court granting final approval to the settlement and providing for the dismissal of the lawsuit with prejudice. Members of the class had until March 12, 2010 to object to the proposed settlement as set forth in the Settlement Agreement; however, no persons objected to the Settlement Agreement. On March 26, 2010, the district court granted final approval of the settlement and dismissed the lawsuit with prejudice, and as a result, the Settlement Agreement became effective thirty days thereafter, thus resolving the lawsuit. In accordance with the terms of the Settlement Agreement, on April 27, 2010, we paid $900,000 to the settlement fund of the class. Pursuant to the terms of a pollution liability policy with Federal Insurance Company, on April 27, 2010, the remaining $1 million of the settlement amount was paid to the settlement fund by our insurance carrier.

19. SUBSEQUENT EVENTS

Derivative Activity

On July 23, 2010, we entered into two derivative commodity transactions. We routinely utilize derivative commodity instruments to mitigate a portion of the exposure to adverse market changes (for additional information on our derivative activities see Note 7, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements). A summary of our new derivative positions is as follows:


Commodity	Period	Volume	Floor Price		Ceiling Price
Natural Gas	Nov 10 – Dec 12	1,560,000 Mcf	$	5.275	$	5.275
Oil	Jan 11 – Dec 12	168,000 Bbls	$	70.000	$	96.650

Acreage Acquisition

On June 30, 2010, our wholly owned subsidiary, Rex Energy Rockies, LLC, a Delaware limited liability company (“Rex Rockies”), entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Duncan Oil Partners, LLC, a Colorado limited liability company (“Duncan”), pursuant to which Rex Rockies agreed to purchase from Duncan all of its right, title and interest in and to certain oil and gas leases covering approximately 26,900 gross (18,700 net) acres located in the DJ Basin in Laramie County, State of Wyoming. Under the terms of the Purchase Agreement, Rex Rockies agreed to pay Duncan a purchase price equal to $1,000 per net leasehold acre conveyed at closing, for a total purchase price of approximately $18.7 million. The Purchase Agreement provided that at closing the purchase price may be adjusted upwards or downwards based upon the final number of net

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

leasehold acres being conveyed by Duncan to Rex Rockies following Rex Rockies’ title review of the oil and gas leases and related assets. Pursuant to the Purchase Agreement, Rex Rockies agreed to pay Duncan approximately $1.9 million to serve as a deposit to be credited toward payment of the purchase price at the closing, which was paid by Rex Rockies concurrently with the execution of the Purchase Agreement.

On July 30, 2010, following its review of title to the oil and gas leases, Rex Rockies purchased Duncan’s oil and gas interests in approximately 18,375 net acres for a total purchase price of approximately $18.4 million, less the deposit previously paid to Duncan. Under the terms of the Purchase Agreement, Rex Rockies may purchase Duncan’s oil and gas interests in an additional 320 net acres in the event that certain title defects relating to the acreage are cured by Duncan within a period of 90 days from the closing date.

Item 2.

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

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2009 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

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

Results of Continuing Operations


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2010		2009		2010		2009
Production:
Oil and Condensate (Bbls)		168,900		183,695		338,655		364,878
Natural Gas (Mcf)		669,512		314,777		1,334,931		621,408
Natural Gas Liquids (Bbls)		4,636		—		9,871		—

Total (Mcfe)^(a)		1,710,728		1,416,947		3,426,087		2,810,676
Average daily production:
Oil and Condensate (Bbls)		1,856		2,019		1,871		2,016
Natural Gas (Mcf)		7,357		3,459		7,375		3,433
Natural Gas Liquids (Bbls)		51		—		55		—

Total (Mcfe)^(a)		18,799		15,571		18,929		15,529
Average sales price:
Oil and Condensate (per Bbl)	$	74.80	$	56.12	$	74.89	$	48.04
Natural Gas (per Mcf)	$	4.10	$	3.83	$	4.77	$	4.48
Natural Gas Liquids (per Bbl)	$	32.65	$	—	$	32.32	$	—

Total (per Mcfe)^(a)	$	9.08	$	8.13	$	9.35	$	7.23
Average NYMEX prices^(b):
Oil (per Bbl)	$	78.16	$	59.83	$	78.35	$	51.51
Natural Gas (per Mcf)	$	4.35	$	3.80	$	4.69	$	4.14

(a)	Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent (“BOE”) to six Mcfe.

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


	Production and Revenue by Basin
	For Three Months Ended June 30,				For Six Months Ended June 30,
	2010		2009		2010		2009
Appalachian
Revenues – Natural Gas	$	2,745,353	$	1,206,003	$	6,365,486	$	2,783,788
Volumes (Mcf)		669,512		314,777		1,334,931		621,408
Average Price	$	4.10	$	3.83	$	4.77	$	4.48
Revenues – Natural Gas Liquids	$	151,381	$	—	$	319,009	$	—
Volumes (Bbl)		4,636		—		9,871		—
Average Price	$	32.65	$	—	$	32.32	$	—
Illinois
Revenues – Oil	$	12,632,960	$	10,309,742	$	25,363,263	$	17,530,186
Volumes (Bbl)		168,900		183,695		338,655		364,878
Average Price	$	74.80	$	56.12	$	74.89	$	48.04

	Other Performance Measurements From Continuing Operations
	For Three Months Ended June 30,				For Six Months Ended June 30,
	2010		2009		2010		2009
EBITDAX (in thousands)	$	5,792	$	4,091	$	12,456	$	12,790
LOE per Mcfe	$	3.39	$	3.70	$	3.42	$	3.70
G&A per Mcfe	$	2.67	$	3.10	$	2.55	$	2.90

General Overview

Operating revenue for the three and six-month periods ended June 30, 2010 increased 35.9% and 59.3%, respectively, when compared to the same periods in 2009. These increases were primarily due to higher oil and gas prices and higher gas production when compared to 2009, which was partially offset by a decrease in oil production. The average sales price per Mcfe during the three and six-month periods ended June 30, 2010 was $9.08 and $9.35, respectively, as compared to $8.13 and $7.23 during the comparable periods of 2009. Total production for the three and six-month periods ended June 30, 2010 increased approximately 20.7% and 21.9%, respectively, when compared to the same periods in 2009. The increase in production can be attributed to the continued success of our Marcellus Shale drilling program in the Appalachian Basin.

Operating expenses increased $2.8 million, or 17.4%, and $3.3 million, or 10.2%, for the three and six-month periods ended June 30, 2010, respectively, as compared to the same periods in 2009. Operating expenses are primarily comprised of: production expenses; G&A expenses; exploration expenses; gains and losses on the disposal of assets; impairment expense; and DD&A expenses. These increases in operating expense can be primarily attributable to increased geological and geophysical activity related to our Marcellus Shale exploration projects. We have also incurred additional operating expenses in relation to our two consolidated variable interest entities, Keystone Midstream and Water Solutions Holdings, which were not in existence during the first half of 2009. For additional information on these entities, see Note 14, Variable Interest Entities, to our Consolidated Financial Statements. Our DD&A expenses decreased due to the increase in the estimated lives of our proved reserves at December 31, 2009, partially offsetting these increases in expense. We calculate our depletion on a units-of-production basis, which decelerated in relation to our higher proved reserve base.

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

•

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

•

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

•

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

•

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

EBITDAX increased approximately $1.7 million to $5.8 million for the three-month period ended June 30, 2010 as compared to the same period in 2009. The increase in EBITDAX can be primarily attributed to higher natural gas production and higher average sales prices for oil and natural gas, resulting in increased operating revenues. EBITDAX decreased approximately $0.3 million to $12.5 million for the six-month period ended June 30, 2010 as compared to the same period in 2009. The decrease in EBITDAX can be primarily attributed to a decrease in realized settlements on commodity derivatives, which was impacted by the early settlement of certain 2011 oil hedges which resulted in receipts of approximately $4.6 million during the first quarter of 2009. Partially offsetting this decrease were higher natural gas production and higher average sales prices for oil and natural gas.

LOE per Mcfe measures the average cost of extracting oil and natural gas from our basin reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our oil and natural gas reserves in the ground. LOE per Mcfe decreased by $0.31 and $0.28 for the three and six months ended June 30, 2010, respectively, as compared to the same periods in 2009. G&A expenses per Mcfe measures overhead costs associated with our management and operations. G&A expenses per Mcfe decreased to approximately $2.67 and $2.55 for the three and six month periods ended June 30, 2010, respectively, as compared to $3.10 and $2.90 for the same periods in 2009.

Comparison of the Three Months Ended June 30, 2010 to the Three Months Ended June 30, 2009.

Oil and gas revenue for the three-month periods ended June 30, 2010 and 2009 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:


	For Three Months Ended June 30,
	2010			2009		Change			%
Oil and Gas Revenues:
Oil and condensate sales revenue	$	12,633		$	10,310	$	2,323		22.5%
Oil derivatives realized^(a)	$	(864	)	$	720	$	(1,584	)	(220.0%)

Total oil and condensate revenue and derivatives realized	$	11,769		$	11,030	$	739		6.7%
Gas sales revenue	$	2,745		$	1,206	$	1,539		127.6%
Gas derivatives realized^(a)	$	1,208		$	824	$	384		46.6%

Total gas revenue and derivatives realized	$	3,953		$	2,030	$	1,923		94.7%
Total natural gas liquid revenue	$	152		$	—	$	152		100.0%
Consolidated sales	$	15,530		$	11,516	$	4,014		34.9%
Consolidated derivatives realized^(a)	$	344		$	1,544	$	(1,200	)	(77.7%)

Total oil and gas revenue and derivatives realized	$	15,874		$	13,060	$	2,814		21.5%
Total Mcfe Production		1,710,728			1,416,947		293,781		20.7%
Average Realized Price per Mcfe	$	9.28		$	9.22	$	0.06		0.7%

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

Average realized price received for oil and gas during the second quarter of 2010 was $9.28 per Mcfe, an increase of 0.7%, or $0.06 per Mcfe, from the same quarter in 2009. The average price for oil and condensate, after the effect of derivative activities, increased 16.0%, or $9.64 per barrel, to $69.68 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 8.4%, or $0.54 per Mcf, to $5.90 per Mcf. Our derivative activities effectively increased net realized price by $0.20 per Mcfe in the second quarter of 2010 and increased net realized prices by $1.09 per Mcfe in the second quarter of 2009.

Production volumes in the second quarter of 2010 increased 20.7% from the second quarter of 2009. Natural gas production increased approximately 113%, primarily due to the production in our Marcellus Shale drilling operations in Westmoreland and Butler Counties in the Commonwealth of Pennsylvania. Oil production decreased approximately 8.1% in the second quarter of 2010 as compared to the same period in 2009, primarily due to natural decline of our oil properties in the Illinois Basin. Overall, our production for the three months ended June 30, 2010 averaged 18,799 Mcfe per day, of which 59.2% was attributable to oil, 39.2% to natural gas and 1.6% was a result of natural gas liquids production.

Other operating revenue for the three months ended June 30, 2010 and June 30, 2009 was approximately $0.2 million and $25,000, respectively. We generate other operating revenue from various activities such as revenue from the transportation of third-party natural gas and the sale and treatment of water used in the drilling of Marcellus Shale wells in the Appalachian Basin. Revenues generated from the sale and treatment of water did not begin until the first quarter of 2010.

Production and lease operating expenses increased approximately $0.6 million, or 10.6%, in the second quarter of 2010 from the same period in 2009. During the latter part of 2008 and into 2009, we implemented several cost reduction measures in an effort to mitigate discretionary spending and to lower production expenses. In relation to increasing oil prices throughout 2009 and into 2010, we have increased our activity levels and increased discretionary spending for maintenance projects that were previously delayed.

G&A expenses for the second quarter of 2010 increased approximately $0.2 million, or 4.1%, to $4.6 million from the same period in 2009. These expenses increased from the second quarter of 2009 to the second quarter of 2010 primarily due to expenses recognized in relation to two variable interest entities for which we consolidate with our financial results that were not in existence during the second quarter of 2009. We have also incurred additional G&A expenses in connection with the operation of our Denver office, which opened in the first quarter of 2010.

(Gain) loss on disposal of assets for the three months ended June 30, 2010 was a gain of approximately $10,000 as compared to a gain of $28,000 for the same period in 2009. We, from time to time, sell or dispose of property and equipment in the normal course of business and recognize a gain or loss based on the price received for those assets compared to the book carrying value at the time of sale or disposal.

Impairment expenses for the second quarter of 2010 totaled approximately $0.6 million as compared to $0.4 million during the comparable period of 2009. These expenses were incurred due to the identification of certain geographic regions that are outside the scope of our current plans, which has increased the probability of future lease expirations. The capitalized costs associated with these properties are periodically evaluated as to their recoverability based on changes brought about by economic factors and potential shifts in our business strategy. As economic and strategic conditions change and we continue to develop unproved properties, our estimates of impairment will likely change and we may increase or decrease expense.

Exploration expense of oil and gas properties for the second quarter of 2010 increased approximately $2.6 million from the same period in 2009. These expenses are primarily associated with seismic data acquisitions and related activities, reservoir characterization and geologic modeling activities, and oil and gas lease delay rental payments. During the second quarter of 2009 we received reimbursements totaling approximately $0.6 million from Williams in accordance with the PEA. For additional information on our joint venture with Williams, see Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated Financial Statements.

DD&A expenses for the three months ended June 30, 2010 decreased approximately $1.0 million, or 16.6%, from $6.2 million for the same period in 2009. This decrease is primarily attributable to the increase in our proved reserves as of December 31, 2009. We calculate our depletion on a units-of-production basis, which decelerated in relation to our higher proved reserves base.

Other operating expenses for the three months ended June 30, 2010 were approximately $0.3 million. These costs were incurred as direct expenditures related to our midstream, water treatment and water sales operations. We did not have midstream, water treatment and water sales operations prior to 2010. See Note 14, Variable Interest Entities, to our Consolidated Financial Statements for more information on our midstream, water treatment and water sales operations.

Interest expense, net of interest income, for the three months ended June 30, 2010 was approximately $0.2 million as compared to $0.2 million for the same period in 2009. The decrease of $38,000 was primarily due to the lower average borrowings on our senior secured line of credit, which was paid in full during the first quarter of 2010 with the proceeds from our public offering of common stock. Also contributing to the decrease was an increase in our average cash balance in the first quarter of 2010, from which we received interest income.

Gain (loss) on derivatives, net includes a gain of approximately $4.3 million for the second quarter of 2010 as compared to a loss of $10.7 million for the same period in 2009. Changes are attributable to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other income (expense) was approximately $0.1 million in the second quarter of 2010 as compared to income of approximately $13,000 for the same period in 2009. Our other expense is characterized by the recognition of gains or losses on the sale of scrap inventory and physical yard inventory adjustments and fluctuates from period to period.

Net income tax expense was approximately $0.1 million for the three months ended June 30, 2010 as compared to an income tax benefit of approximately $5.8 million for the three months ended June 30, 2009. The change was due to net income during the second quarter of 2010 that was primarily attributable to increased production, higher commodity prices and increased gains from derivative activities as compared to the second quarter of 2009.

Net income attributable to Rex Energy for the second quarter of 2010 was approximately $0.9 million, as compared to a net loss of approximately $9.4 million for the comparable period in 2009 as a result of the factors discussed above.

Comparison of the Six Months Ended June 30, 2010 to the Six Months Ended June 30, 2009.

Oil and gas revenue for the six-month periods ended June 30, 2010 and 2009 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:


	For Six Months Ended June 30,
	2010			2009		Change			%
Oil and Gas Revenues:
Oil and condensate sales revenue	$	25,363		$	17,530	$	7,833		44.7%
Oil derivatives realized^(a)(b)	$	(1,698	)	$	3,983	$	(5,681	)	(142.6%)

Total oil and condensate revenue and derivatives realized	$	23,665		$	21,513	$	2,152		10.0%
Gas sales revenue	$	6,366		$	2,784	$	3,582		128.7%
Gas derivatives realized^(a)	$	1,807		$	1,333	$	474		35.6%

Total gas revenue and derivatives realized	$	8,173		$	4,117	$	4,056		98.5%
Total natural gas liquid revenue	$	319		$	—	$	319		100.0%
Consolidated sales	$	32,048		$	20,314	$	11,734		57.8%
Consolidated derivatives realized^(a)(b)	$	109		$	5,316	$	(5,207	)	(97.9%)

Total oil and gas revenue and derivatives realized	$	32,157		$	25,630	$	6,527		25.5%
Total Mcfe Production		3,426,087			2,810,676		615,411		21.9%
Average Realized Price per Mcfe	$	9.39		$	9.12	$	0.27		3.0%

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

(b)	For the six months ended June 30, 2010, excludes approximately $4.6 million in proceeds that were received upon the early settlement of oil hedges relating to the 2011 calendar year.

Average realized price received for oil and gas during the first half of 2010 was $9.39 per Mcfe, an increase of 3.0%, or $0.27 per Mcfe, from the same period in 2009. The average price for oil and condensate, after the effect of derivative activities, increased 18.5%, or $10.92 per barrel, to $69.88 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 7.6%, or $0.50 per Mcf, to $6.12 per Mcf. Our derivative activities effectively increased net realized price by $0.03 per Mcfe in the first six months of 2010 and increased net realized prices by $1.89 per Mcfe in the first six months of 2009.

Production volumes in the first half of 2010 increased 21.9% from the first half of 2009. Natural gas production increased approximately 115%, primarily due to the production in our Marcellus Shale drilling operations in Westmoreland and Butler Counties in the Commonwealth of Pennsylvania. Oil production decreased approximately 7.2% in the first half of 2010 as compared to the same period in 2009, primarily due to natural decline of our oil properties in the Illinois Basin. Overall, our production for the six months ended June 30, 2010 averaged 18,929 Mcfe per day, of which 59.3% was attributable to oil, 39.0% to natural gas and 1.7% was a result of natural gas liquids production.

Other operating revenue for the six months ended June 30, 2010 and June 30, 2009 was approximately $0.4 million and $57,000, respectively. We generate other operating revenue from various activities such as revenue from the transportation of third-party natural gas and the sale and treatment of water used in the drilling of Marcellus Shale wells in the Appalachian Basin. Revenues generated from the sale and treatment of water did not begin until the first quarter of 2010.

Production and lease operating expenses increased approximately $1.3 million, or 12.7%, in the first half of 2010 from the same period in 2009. During the latter part of 2008 and into 2009, we implemented several cost reduction measures in an effort to mitigate discretionary spending and to lower production expenses. In relation to increasing oil prices throughout 2009 and into 2010, we have increased our activity levels and increased discretionary spending for maintenance projects that were previously delayed.

G&A expenses for the first six months of 2010 increased approximately $0.6 million, or 7.3%, to $8.7 million from the same period in 2009. These expenses increased from the first half of 2009 to the first half of 2010 primarily due to expenses recognized in relation to two variable interest entities for which we consolidate with our financial results that were not in existence during the second quarter of 2009. We have also incurred additional G&A expenses in connection with the operation of our Denver office, which opened in the first quarter of 2010.

(Gain) loss on disposal of assets for the six months ended June 30, 2010 was a gain of approximately $7,000 as compared to a loss of $0.4 million for the same period in 2009. During the first quarter of 2009, we sold our Permian Basin assets, which resulted in a loss of approximately $0.4 million. For additional information on the sale of these assets see Note 12, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements. We, from time to time, sell or dispose of property and equipment in the normal course of business and recognize a gain or loss based on the price received for those assets compared to the book carrying value at the time of sale or disposal.

Impairment expenses for the first half of 2010 totaled approximately $1.1 million as compared to $0.4 million during the comparable period of 2009. These expenses were incurred due to the identification of certain geographic regions that are outside the scope of our current plans, which has increased the probability of future lease expirations. The capitalized costs associated with these properties are periodically evaluated as to their recoverability based on changes brought about by economic factors and potential shifts in our business strategy. As economic and strategic conditions change and we continue to develop unproved properties, our estimates of impairment will likely change and we may increase or decrease expense.

Exploration expense of oil and gas properties for the first half of 2010 increased approximately $2.6 million from the same period in 2009. These expenses are primarily associated with seismic data acquisitions and related activities, reservoir characterization and geologic modeling activities, and oil and gas lease delay rental payments. During the second quarter of 2009 we received reimbursements totaling approximately $0.6 million from Williams in accordance with the PEA. For additional information on our joint venture with Williams, see Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated Financial Statements.

DD&A expenses for the six months ended June 30, 2010 decreased approximately $2.1 million, or 16.9%, from $12.3 million for the same period in 2009. This decrease is primarily attributable to the increase in our proved reserves as of December 31, 2009. We calculate our depletion on a units-of-production basis, which decelerated in relation to our higher proved reserves base.

Other operating expenses for the six months ended June 30, 2010 were approximately $0.6 million. These costs were incurred as direct expenditures related to our midstream, water treatment and water sales operations. We did not have midstream, water treatment and water sales operations prior to 2010. See Note 14, Variable Interest Entities, to our Consolidated Financial Statements for more information on our midstream, water treatment and water sales operations.

Interest expense, net of interest income, for the six months ended June 30, 2010 was approximately $0.3 million as compared to $0.4 million for the same period in 2009. The decrease of $0.1 million was primarily due to the lower average borrowings on our senior secured line of credit, which was paid in full during the first quarter of 2010 with the proceeds from our public offering of common stock. Also contributing to the decrease was an increase in our average cash balance in the first quarter of 2010, from which we received interest income.

Gain (loss) on derivatives, net includes a gain of approximately $8.1 million for the first half of 2010 as compared to a loss of $5.2 million for the same period in 2009. Changes are attributable to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market. During the first quarter of 2009 we received proceeds of approximately $4.6 million related to the early settlement of oil hedges that related to 2011 production.

Other income (expense) was an expense of approximately $0.2 million in the first half of 2010 as compared to expense of approximately $32,000 for the same period in 2009. Our other expense is characterized by the recognition of gains or losses on the sale of scrap inventory and physical yard inventory adjustments and fluctuates from period to period.

Net income tax expense was approximately $1.4 million for the six months ended June 30, 2010 as compared to an income tax benefit of approximately $7.0 million for the six months ended June 30, 2009. The change was due to net income during the first half of 2010 that was primarily attributable to increased production, higher commodity prices and increased gains from derivative activities as compared to the first half of 2009.

Net income attributable to Rex Energy for the first six months of 2010 was approximately $2.9 million, as compared to a net loss of approximately $10.5 million for the comparable period in 2009 as a result of the factors discussed above.

Capital Resources and Liquidity

Our primary needs for cash are for exploration, development and acquisition of oil and gas properties. During the six months ended June 30, 2010, $79.7 million of capital was expended on drilling projects, facilities and related equipment and acquisitions of unproved acreage. The capital program was funded by net cash flow from operations and proceeds from our January 2010 public offering of common stock and through borrowings under our Senior Credit Facility. Our 2010 capital budget is expected to continue to be funded primarily by cash flow from operations and borrowings under our Senior Credit Facility. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a significant continuation of depressed commodity prices, particularly natural gas, or reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may also elect to issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Financial Condition and Cash Flows for the Six Months Ended June 30, 2010 and 2009

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


	Six Months Ended June 30, ($ in Thousands)
	2010			2009
Cash flows provided by operations	$	6,263		$	6,391
Cash flows used in investing activities		(82,990	)		(11,023	)
Cash flows provided by financing activities		84,523			—

Net increase (decrease) in cash and cash equivalents	$	7,796		$	(4,632	)

Net cash provided by operating activities decreased by approximately $0.1 million in the first six months of 2010 over the same period in 2009. The decrease in 2010 was affected by a combination of factors, but was primarily due to increased operating expenses thus far in 2010 in addition to the receipt of approximately $4.6 million related to the early settlement of 2011 oil hedges during the first quarter of 2009. Partially offsetting these cash flow decreases were increased production and increased commodity prices. Average sales prices, excluding realized derivatives, increased from $7.23 per Mcfe in the first six months of 2009 to $9.35 per Mcfe in the first six months of 2010. Additionally, production grew from 2,810,676 Mcfe in the first half of 2009 to 3,426,087 Mcfe in the first half of 2010.

Net cash used in investing activities increased by approximately $72.0 million from the first six months of 2009 to $83.0 million in the first six months of 2010. This change can be primarily explained by the increased capital spending during the first half of 2010 as compared to the first half of 2009. Also contributing to the change was approximately $17.3 million in proceeds received by us in connection with the sale of our Southwest Region assets during the first quarter of 2009.

Net cash provided by (used in) financing activities increased by approximately $84.5 million from the first six months of 2009 to the first six months of 2010. The increase is primarily due to our public offering of common stock during the first quarter of 2010, from which we received net proceeds of approximately $80.2 million.

Effects of Inflation and Changes in Price

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

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended June 30, 2010, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2009. We describe critical recently adopted and issued accounting standards in Item 1. Financial Statements—Note 4, “Recently Issued Accounting Pronouncements.”

Non-GAAP Financial Measures

EBITDAX

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

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

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

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

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net Income (Loss) From Continuing Operations	$	813		$	(9,437	)	$	2,803		$	(10,784	)
Add Back Depletion, Depreciation, Amortization and Accretion		5,139			6,162			10,232			12,317
Add Back Non-Cash Compensation Expense		521			621			954			1,096
Add Back Interest Expense^(a)		362			379			722			774
Add Back Impairment Expense		577			419			1,148			435
Add Back (Less) Exploration Expenses (Income)		2,311			(247	)		3,446			835
Less Interest Income		(16	)		(1	)		(51	)		(2	)
Add Back (Less) Loss (Gain) on Disposal of Assets		(10	)		(28	)		(7	)		400
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives		(4,112	)		12,064			(8,335	)		14,764
Add Back Noncontrolling Interest Net Loss		64			—			120			—
Add Back (Less) Income Tax Expense (Benefit)		143			(5,841	)		1,424			(7,045	)

EBITDAX From Continuing Operations	$	5,792		$	4,091		$	12,456		$	12,790
Add EBITDAX From Discontinued Operations		—			—			—			53

EBITDAX	$	5,792		$	4,091		$	12,456		$	12,843

(a)	Includes settlements on interest rate swap.

Volatility of Oil and Natural Gas Prices

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

For the three and six month periods ended June 30, 2010, the net realized gains on oil and natural gas derivatives were approximately $0.3 million and $0.1 million, respectively, as compared to net realized gains of approximately $1.5 million and $9.9 for the comparable periods in 2009. Included in the net realized gain in the six months ended June 30, 2010 were cash settlements of approximately $4.6 million which resulted from the early settlement of certain oil hedges related to production in 2011. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

For the three and six month periods ended June 30, 2010, the net unrealized gain on oil and natural gas derivatives was $4.1 million and $8.3 million, respectively, as compared to losses of $12.1 million and $14.8 million for the comparable period in 2009. The net unrealized gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

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

For a summary of our current oil and natural gas derivative positions at June 30, 2010, refer to Note 7 of our Consolidated Financial Statements, “Fair Value of Financial Instruments and Derivative Instruments”.

Item 3.

Quantitative And Qualitative Disclosures About Market Risk.

We are exposed to various risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial amount of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Conversely, increases in the market prices for oil and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on June 30, 2010 production, we project that a 10% decline in the price per barrel of oil and the price per Mcf of gas from the first half 2010 average would reduce our gross revenues, before the effects of derivatives, for the remaining six months of 2010 by approximately $3.2 million.

We have designed our hedging policy to reduce the risk of price volatility for our production in the natural gas and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps and collars. The volume of derivative instruments that we may use are 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 will 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 hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

At June 30, 2010, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume	Average Derivative Price	Fair Market Value ($ in Thousands)
Oil
2010	Swap	90,000 Bbls	$62.20	$	(1,305	)
2010	Collar	204,000 Bbls	$62.94 - $86.85	$	(333	)
2011	Collar	408,000 Bbls	$67.94 - $107.31	$	1,235
2012	Collar	192,000 Bbls	$66.25 - $125.66	$	752

	Total	894,000 Bbls		$	349
Natural Gas
2010	Swap	60,000 Mcf	$6.00	$	71
2010	Put	540,000 Mcf	$6.31	$	858
2010	Collar	720,000 Mcf	$5.98 - $8.35	$	938
2011	Collar	1,800,000 Mcf	$5.27 - $7.05	$	732
2011	Put	720,000 Mcf	$8.00	$	1,957
2012	Collar	1,200,000 Mcf	$5.78 - $6.91	$	465

	Total	5,040,000 Mcf		$	5,021

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations. We use the interest rate swap agreement to manage risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. Under our interest rate swap agreement, we agree to pay an amount equal to a specified rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount.

As of June 30, 2010, the following interest rate swap derivative was outstanding ($ in thousands):


Period^(a)	Contract Type	Amount	Interest Rate	Fair Market Value
4/1/10 – 11/30/10	Swap	$20,000	4.15%	$(356)

(a)

Item 305 (a) of Regulation S-K requires that tabular information relating to contract terms allow readers of the table to determine expected cash flows from the market risk sensitive instruments for each of the next five years. At June 30, 2010, we had an interest rate swap derivative contract in place that expires on November 30, 2010.

Item 4.

Controls And Procedures.

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

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1.

Legal Proceedings.

The information set forth in Note 18, Litigation, to our Consolidated Financial Statements included in Item 1 of Part I of this report is incorporated herein by reference.

Item 1A.

Risk Factors.

During the quarter ended June 30, 2010, there were no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2009.

Item 6.

Exhibits.


Exhibit Number		Exhibit Title

3.1		Certificate of Incorporation of Rex Energy Corporation, as amended (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K as filed with the SEC on March 3, 2010).

3.3		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.1		Independent Director Agreement by and between Rex Energy Corporation and Eric L. Mattson dated April 30, 2010 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on April 30, 2010).

10.2		Purchase and Sale Agreement dated June 28, 2010 by and between Rex Energy Rockies, LLC and Duncan Oil Partners, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on July 7, 2010).

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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.


	REX ENERGY CORPORATION (Registrant)

Date: August 4, 2010	By:	/S/ BENJAMIN W. HULBURT
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: August 4, 2010	By:	/S/ THOMAS C. STABLEY
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

EXHIBIT INDEX


Exhibit Number		Exhibit Title

3.1		Certificate of Incorporation of Rex Energy Corporation, as amended (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K as filed with the SEC on March 3, 2010).

3.3		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.1		Independent Director Agreement by and between Rex Energy Corporation and Eric L. Mattson dated April 30, 2010 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on April 30, 2010).

10.2		Purchase and Sale Agreement dated June 28, 2010 by and between Rex Energy Rockies, LLC and Duncan Oil Partners, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on July 7, 2010).

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.

Large Accelerated filer

Accelerated filer

Non-accelerated filer

Smaller Reporting Company