Rex Energy 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

OR

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

For the transition period from              to              .

Commission file number: 001-33610

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

476 Rolling Ridge Drive, Suite 300

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

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

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

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

Large Accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller Reporting Company	¨

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

52,853,214 common shares, par value $.001 per share, were outstanding on November 5, 2012.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD September 30, 2012

INDEX

		PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			2
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements		4
	Consolidated Balance Sheets As of September 30, 2012 (Unaudited) and December 31, 2011		4
	Consolidated Statements of Operations (Unaudited) for the three and nine-month periods ended September 30, 2012 and September 30, 2011		5
	Consolidated Statement of Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) (Unaudited) for the nine-month period ended September 30, 2012		6
	Consolidated Statements of Cash Flows (Unaudited) for the nine-month periods ended September 30, 2012 and September 30, 2011		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 Disclosures About Market Risk		42
Item 4.	Controls and Procedures		43
PART II. OTHER INFORMATION			44
Item 1.	Legal Proceedings		44
Item 1A.	Risk Factors		44
Item 6.	Exhibits
SIGNATURES
EXHIBIT INDEX

2

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains 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 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 those expressed or implied by us in forward-looking statements include, among others, the following:

• economic conditions in the United States and globally;

• domestic and global supply and demand for oil and natural gas;

• volatility in oil, NGL and natural gas, NGLs pricing;

• new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our operations;

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

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

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

• drilling and operating risks;

• the success of our drilling techniques in both conventional and unconventional reservoirs;

• the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future;

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

• the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;

• the availability of equipment, such as drilling rigs, and infrastructure, such as transportation pipelines, processing and midstream services;

• the effects of adverse weather or other natural disasters on our operations;

• competition in the oil and gas industry in general, and specifically in our areas or operations;

• changes in our drilling plans and related budgets;

• the success of prospect development and property acquisitions;

• the success of our business and financial strategies, and hedging strategies;

• conditions in the domestic and global capital and credit markets and their effect on us;

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

• uncertainties related to the legal and regulatory environment for our industry, and our own 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, 2011 filed with the U.S. Securities and Exchange Commission and under “Risk Factors” in Part II, Item 1A to this Quarterly Report on Form 10-Q for the quarter ended September 30, 2012.

Because these 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 forward looking-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.

3

Item 1. Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

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

	September 30,  2012 (unaudited)			December 31, 2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,783		$	11,796
Accounts Receivable		25,898			17,717
Short-Term Derivative Instruments		9,275			10,404
Assets Held for Sale		10,439			24,808
Inventory, Prepaid Expenses and Other		1,273			1,191
Total Current Assets		50,668			65,916
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		463,310			349,938
Unevaluated Oil and Gas Properties		159,763			123,241
Other Property and Equipment		49,140			43,542
Wells and Facilities in Progress		85,707			66,548
Pipelines		6,706			4,408
Total Property and Equipment		764,626			587,677
Less: Accumulated Depreciation, Depletion and Amortization		(137,794	)		(107,433	)
Net Property and Equipment		626,832			480,244
Deferred Financing Costs and Other Assets – Net		2,622			3,405
Equity Method Investments		17,161			41,683
Long-Term Deferred Tax Asset		0			1,727
Long-Term Derivative Instruments		2,253			8,576
Total Assets	$	699,536		$	601,551
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	34,541		$	41,558
Accrued Expenses		24,693			15,682
Short-Term Derivative Instruments		1,900			2,363
Current Deferred Tax Liability		2,049			2,141
Liabilities Related to Assets Held for Sale		539			1,622
Total Current Liabilities		63,722			63,366
Senior Secured Line of Credit and Long-Term Debt		172,751			225,138
Long-Term Derivative Instruments		2,454			1,275
Long-Term Deferred Tax Liability		17,865			84
Other Deposits and Liabilities		3,818			744
Asset Retirement Obligation		24,085			18,670
Total Liabilities	$	284,695		$	309,277
Commitments and Contingencies (See Note 11)
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 52,853,214 shares issued and outstanding on September 30, 2012 and 44,859,220 shares issued and outstanding on December 31, 2011		52			44
Additional Paid-In Capital		450,099			376,843
Accumulated Deficit		(35,972	)		(84,888	)
Rex Energy Stockholders’ Equity		414,179			291,999
Noncontrolling Interests		662			275
Total Stockholders’ Equity		414,841			292,274
Total Liabilities and Stockholders’ Equity	$	699,536		$	601,551

See accompanying notes to the unaudited consolidated financial statements

4

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in Thousands, Except per Share Data)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	34,711		$	30,259		$	93,893		$	81,087
Field Services Revenue		4,170			442			8,990			1,679
Other Revenue		48			54			137			158
TOTAL OPERATING REVENUE		38,929			30,755			103,020			82,924
OPERATING EXPENSES
Production and Lease Operating Expense		11,234			8,990			34,505			24,055
General and Administrative Expense		6,858			4,461			18,043			18,603
Loss on Disposal of Assets		16			6			110			464
Impairment Expense		292			2,379			3,357			2,928
Exploration Expense		1,206			303			3,511			2,203
Depreciation, Depletion, Amortization and Accretion		12,396			7,762			33,082			19,641
Field Services Operating Expense		2,985			618			5,706			1,637
Other Operating Expense (Income)		399			(23	)		693			(85	)
TOTAL OPERATING EXPENSES		35,386			24,496			99,007			69,446
INCOME FROM OPERATIONS		3,543			6,259			4,013			13,478
OTHER INCOME (EXPENSE)
Interest Expense		(852	)		(474	)		(3,655	)		(1,024	)
Gain (Loss) on Derivatives, Net		(5,893	)		12,174			5,188			12,787
Other Income (Expense)		(497	)		42			92,241			61
Income (Loss) on Equity Method Investments		(174	)		105			(3,738	)		(165	)
TOTAL OTHER INCOME (EXPENSE)		(7,416	)		11,847			90,036			11,659
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(3,873	)		18,106			94,049			25,137
Income Tax (Expense) Benefit		2,131			(5,440	)		(35,768	)		(8,207	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		(1,742	)		12,666			58,281			16,930
Loss From Discontinued Operations, Net of Income Taxes		(258	)		(20,812	)		(8,662	)		(29,195	)
NET INCOME (LOSS)		(2,000	)		(8,146	)		49,619			(12,265	)
Net Income (Loss) Attributable to Noncontrolling Interests		193			44			516			(14	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(2,193	)	$	(8,190	)	$	49,103		$	(12,251	)
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders	$	(0.04	)	$	0.29		$	1.13		$	0.39
Basic – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders		0.00			(0.47	)		(0.17	)		(0.67	)
Basic – Net Income (Loss) Attributable to Rex Common Shareholders	$	(0.04	)	$	(0.18	)	$	0.96		$	(0.28	)
Basic – Weighted Average Shares of Common Stock Outstanding		52,036			43,951			51,120			43,897
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders	$	(0.04	)	$	0.28		$	1.11		$	0.38
Diluted – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders		0.00			(0.47	)		(0.17	)		(0.66	)
Diluted – Net Income (Loss) Attributable to Rex Common Shareholders	$	(0.04	)	$	(0.19	)	$	0.94		$	(0.28	)
Diluted – Weighted Average Shares of Common Stock Outstanding		52,805			44,384			52,018			44,448

See accompanying notes to the unaudited consolidated financial statements

5

REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN NONCONTROLLING INTERESTS AND STOCKHOLDERS’ EQUITY (DEFICIT)

FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2012

(Unaudited, in Thousands)

	Common Stock					Additional		Accumulated Deficit			Rex Energy Stockholders’ Equity					Total
	Shares			Par Value		Paid-In Capital							Noncontrolling Interests			Stockholders’ Equity
BALANCE December 31, 2011		44,859		$	44	$	376,843	$	(84,888	)	$	291,999	$	275		$	292,274
Stock-Based Compensation		0			0		2,319		(187	)		2,132		0			2,132
Issuance of common stock, net of issuance costs		8,050			8		70,575		0			70,583		0			70,583
Stock Option Exercises		35			0		362		0			362		0			362
Issuance of Restricted Stock, Net of Forfeitures		(91	)		0		0		0			0		0			0
Capital Distributions		0			0		0		0			0		(129	)		(129	)
Net Income		0			0		0		49,103			49,103		516			49,619
BALANCE September 30, 2012		52,853		$	52	$	450,099	$	(35,972	)	$	414,179	$	662		$	414,841

See accompanying notes to the unaudited consolidated financial statements

6

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Nine Months  Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	49,619		$	(12,265	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		3,738			165
Non-cash Expenses		2,154			1,435
Depreciation, Depletion, Amortization and Accretion		33,082			19,718
Unrealized (Gain) Loss on Derivatives		8,168			(8,972	)
Dry Hole Expense		613			30,529
Deferred Income Tax Expense (Benefit)		19,416			(7,172	)
Impairment Expense		16,308			14,182
(Gain) Loss on Sale of Asset		(91,980	)		464
Changes in operating assets and liabilities
Accounts Receivable		(8,154	)		11,304
Inventory, Prepaid Expenses and Other Assets		(50	)		(108	)
Accounts Payable, Accrued Expenses and Income Taxes Payable		(46	)		3,632
Other Assets and Liabilities		(7,035	)		(939	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		25,833			51,973
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		237			3,137
Change in Restricted Cash		0			16,086
Contributions to Equity Method Investments		(4,087	)		(14,412	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		122,711			2,570
Acquisitions of Undeveloped Acreage		(43,369	)		(60,468	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(126,823	)		(143,894	)
NET CASH USED IN INVESTING ACTIVITIES		(51,331	)		(196,981	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(155,000	)		0
Proceeds from Long-Term Debt and Line of Credit		102,730			144,000
Repayments of Loans and Other Notes Payable		(664	)		(650	)
Debt Issuance Costs		(195	)		(916	)
Payments Related to Settlement of Tax Withholdings Related to Share-Based Compensation Awards		(234	)		0
Contributions (Distributions) by the Partners of Consolidated Joint Ventures		(129	)		7
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		70,977			1,160
NET CASH PROVIDED BY FINANCING ACTIVITIES		17,485			143,601
NET DECREASE IN CASH		(8,013	)		(1,407	)
CASH – BEGINNING		11,796			11,008
CASH – ENDING	$	3,783		$	9,601
SUPPLEMENTAL DISCLOSURES
Interest Paid		3,783			748
Cash Paid for Income Taxes		11,370			49
NON-CASH ACTIVITIES
Equipment Financing		1,768			340

See accompanying notes to the unaudited consolidated financial statements

7

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil and gas company with operations currently focused in the Appalachian and Illinois Basins. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects and Utica Shale and Upper Devonian Shale exploration activities. In the Illinois Basin, in addition to our developmental oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. Our balanced growth strategy is focused on developing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties. In addition to our exploration and production activities, we have a field services segment which engages in the acquisition, management and operation of water treatment, water disposal and water transportation in the Appalachian Basin.

The accompanying 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. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. 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.

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. 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 reclassifications have been made to prior period financial statements to conform to the current period presentation. These reclassifications had no effect on the Company’s previously reported results of operations.

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 Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2011.

Discontinued Operations

During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming, Colorado and Nebraska. Pursuant to the rules for discontinued operations, these assets have been classified as Assets Held for Sale on our Consolidated Balance Sheets and the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations. Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 3,Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

Subsidiary Guarantors

We filed a registration statement on Form S-3, which became effective June 15, 2011, with respect to certain securities described therein, including debt securities, which may be guaranteed by certain of our subsidiaries. Rex Energy Corporation is a holding company with no independent assets or operations. We contemplate that if guaranteed debt securities are offered pursuant to the registration statement, all guarantees will be full and unconditional and joint and several and any subsidiaries other than the subsidiary guarantors will be minor. In addition, there are no significant restrictions on the ability of Rex Energy Corporation to receive funds from our subsidiaries through dividends, loans, advances or otherwise.

2. ASSET RETIREMENT OBLIGATION

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. If a natural gas or oil well is sold, the liability would be 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.

8

Accretion expense totaled approximately $0.6 million and $1.5 million for the three and nine months ended September 30, 2012, respectively, as compared to $0.3 million and $1.0 million for the three and nine months ended September 30, 2011, respectively. These amounts are recorded as depreciation, depletion and amortization (“DD&A”) expense on our Consolidated Statements of Operations. During the first nine months of 2012, we recognized an increase of $3.8 million in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The primary factor underlying the 2012 fair value revisions was an overall increase in abandonments estimates.

	September 30, 2012
	($ in Thousands)
Beginning Balance at December 31, 2011	$	18,670
Asset Retirement Obligation Incurred		417
Asset Retirement Obligation Settled		(390	)
Asset Retirement Obligation Revision of Estimated Obligation		3,846
Asset Retirement Obligation Accretion Expense		1,542
Total Future Abandonment Cost	$	24,085

3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming, Colorado and Nebraska, and we engaged an advisor to assist with the marketing efforts. The assets are available for immediate sale pending normal due diligence to be conducted in the course of business, with consummation of a sale, or sales, expected within one year. The recording of DD&A expense related to our DJ Basin assets ceased in December 2011. For the three and nine-month periods ended September 30, 2012, we recorded impairment expense of approximately $0 million and $13.0, respectively. We continually evaluate the value, less cost to sell, of our DJ Basin assets to determine if the fair value of our assets is less than their carrying amount based on changes in market conditions. Based on recent purchase and sale activities in the Basin, management believes our carrying value for the assets to be adequate. Upon the completion of a sale, we will have no continuing activities in the DJ Basin or continuing cash flows from this region.

These assets have been classified as Assets Held for Sale on our Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011, and the results of operations are reflected in Discontinued Operations in our Consolidated Statements of Operations. We have included $10.4 million and $24.8 million of assets located in the DJ Basin as Assets Held for Sale on our Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011, respectively. Our Assets Held for Sale primarily consists of undeveloped acreage in the states of Wyoming, Colorado and Nebraska. We have included approximately $0.5 million and $1.6 million of liabilities as Liabilities Related to Assets Held for Sale on our Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011, respectively. These liabilities primarily relate to Accounts Payable and Accrued Expenses.

9

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 Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in Thousands)	2012			2011			2012			2011
Revenues:
Oil, Natural Gas and NGL Sales	$	29		$	83		$	81		$	485
Total Operating Revenue		29			83			81			485
Costs and Expenses:
Production and Lease Operating Expense		97			110			305			401
General and Administrative Expense		60			428			583			1,457
Exploration Expense		329			30,249			810			31,562
Impairment Expense		0			0			12,951			11,255
Depreciation, Depletion, Amortization and Accretion		0			(84	)		0			77
Loss on Sale of Assets		4			0			148			0
Other Operating Expense		0			0			8			0
Other Expense		0			0			2			1
Total Costs and Expenses		490			30,703			14,807			44,753
Loss from Discontinued Operations Before Income Taxes		(461	)		(30,620	)		(14,726	)		(44,268	)
Income Tax Benefit		203			9,808			6,064			15,073
Loss from Discontinued Operations, net of taxes	$	(258	)	$	(20,812	)	$	(8,662	)	$	(29,195	)
Production:
Crude Oil (Bbls)		407			1,113			1,062			6,023

4. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In December 2011, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2011-11,Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. ASU 2011-11 provides new disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with International Financial Reporting Standards (“IFRS”) and U.S. GAAP. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods, including retrospective application for all comparative periods presented. Although we currently are not engaged in any arrangements that would be effected by these disclosure requirements, we believe that ASU 2011-11 may have a material impact on future disclosures pending our entrance into an offsetting arrangement.

In May 2011, the FASB issued ASU 2011-04,Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 generally provides a uniform framework for fair value measurements and related disclosures between U.S. GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation process used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a nonfinancial asset that is different from the asset’s highest and best use, the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosures of all transfers between Level 1 and Level 2 of the fair value hierarchy. This update is effective for annual and interim periods beginning on or after December 31, 2011. We adopted ASU 2011-04 on January 1, 2012 with no material impact.

5. CONCENTRATIONS OF CREDIT RISK

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 counterparties 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 high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 6,Long-term Debt, to our Consolidated Financial Statements). We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from

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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. Approximately 92.6% of our production receivables from continuing operations at December 31, 2011 were attributable to four customers, with the largest single purchaser accounting for 56.2%. Five customers accounted for approximately 91.1% of our production receivables from continuing operations as of September 30, 2012, with the largest single purchaser accounting for 35.4%. We believe the growth in our Appalachian Basin operations will help us to minimize our future risks by diversifying our ratio of oil and natural gas sales as well as the quantity of purchasers.

6. LONG-TERM DEBT

Senior Credit Facility

We maintain a revolving credit facility evidenced by a Credit Agreement, dated September 28, 2007, with KeyBank National Association as Administrative Agent; Royal Bank of Canada, as Syndication 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 by reference to our oil and gas properties. As of September 30, 2012, the borrowing base under the Senior Credit Facility was $290.0 million; however, the revolving credit facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions described in the agreement. The borrowing base is re-determined by the bank group semi-annually. As of September 30, 2012, loans made under the Senior Credit Facility were set to mature on September 28, 2015. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of September 30, 2012, we had $122.0 million drawn on the Senior Credit Facility as compared to $175.0 million at December 31, 2011.

Borrowings under the Senior Credit Facility bear interest, at our election, at the Adjusted LIBOR or the Alternate Base Rate (each 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 2.75% for Eurodollar loans and 0.50% to 1.50% for Alternate Base Rate loans. The Alternate 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 0.5%; and (iii) the London Interbank Offered Rate for deposits with a maturity comparable to the borrowings (“LIBOR”) 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 0.375% to 0.50%. On September 5, 2012, we entered into an amendment to the Senior Credit Facility to increase the borrowing base to $290.0 million from $265.0 million.

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 rates 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 Pennsylvania, 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 our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, impairment, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter,

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our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day is to not be less than 1.0 to 1.0. On that basis, our current ratio as of September 30, 2012 was approximately 4.2 to 1.0. Additionally, the Senior Credit Facility requires 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, known as our interest coverage ratio, is not to be less than 3.0 to 1.0. Our interest coverage ratio as of September 30, 2012 was approximately 26.6 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 4.25 to 1.0. Our ratio of total debt to EBITDAX as of September 30, 2012 was approximately 1.9 to 1.0.

Second Lien Credit Agreement

On December 22, 2011, we entered into a second lien credit agreement (the “Second Lien Credit Agreement”) with KeyBank, as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, UnionBanCal Equities, Inc. and SunTrust Bank, as Co-Documentation agents, and the lenders from time to time party thereto. The Second Lien Credit Agreement provides for a $100.0 million senior secured second lien term loan facility under which $50.0 million is initially available to us and up to an additional $50.0 million of incremental borrowings may be available upon the request of the Company. The initial borrowings under the Second Lien Credit Agreement mature on March 28, 2016. The maturity of incremental borrowings, if any, will be determined at the time of such borrowings. In certain circumstances, we may be required to prepay borrowings under the Second Lien Credit Agreement. Management does not believe that a prepayment will be required within the next twelve months. On September 5, 2012, and in conjunction with the amendment to the Senior Credit Facility, we entered into an amendment to Second Lien Credit Agreement to, among other things, reduce the required hedging period from 36 months to 24 months.

At our election, borrowings under the Second Lien Credit Agreement bear interest at a rate per annum equal to the “Alternate Base Rate” or “Adjusted LIBOR” (each as defined below), plus, in each case, an applicable per annum margin. The Alternate 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 0.5%; and (iii) LIBOR (which for purposes of this agreement shall never be less than 1.0%) plus 1.0%. Adjusted LIBOR is equal to the product of the LIBOR Rate multiplied by a statutory reserve rate. The applicable per annum margin equals, in the case of loans bearing interest at the Alternate Base Rate, 5.0% through the first anniversary of the initial borrowings and 6.0% thereafter, and in the case of Adjusted LIBOR loans, 6.0% through the first anniversary of the initial borrowings and 7.0% thereafter. Interest is payable quarterly in the case of loans bearing interest at the Alternate Base Rate and on the last day of each relevant interest period or every three months in the case of loans bearing interest at the Adjusted LIBOR.

The Second Lien Credit Agreement contains covenants that restrict our ability to, among other things, materially change our business, make dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions. The Second Lien Credit Agreement states that as of the last day of any fiscal quarter, our current ratio must not be less than 1.0 to 1.0. Our current ratio as of September 30, 2012 was approximately 4.2 to 1.0. Additionally, the Second Lien Credit Agreement states that as of the last day of any fiscal quarter, our interest coverage ratio for the period of four fiscal quarters ending on such day must not to be less than 3.0 to 1.0. Our interest coverage ratio as of September 30, 2012 was approximately 26.6 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 4.25 to 1.0. Our ratio of total debt to EBITDAX as of September 30, 2012 was approximately 1.9 to 1.0. Obligations under the Second Lien Credit Agreement are secured by mortgages on our oil and gas properties. We are required to maintain liens covering our oil and gas properties representing at least 80% of the total value of all of our oil and gas properties.

In connection with the Second Lien Credit Agreement, we entered into a guaranty and second lien collateral agreement, dated as of December 22, 2011, in favor of KeyBank, as Administrative Agent for the banks and other financial institutions from time to time party to the Second Lien Credit Agreement (“the “Guaranty and Second Lien Collateral Agreement”). Pursuant to the Guaranty and Second Lien Collateral Agreement, we, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Second Lien Credit Agreement. In addition, we granted, as security for the prompt and complete payment and performance when due of such obligations, a security interest in substantially all of our personal property, including equity interests. As of September 30, 2012 and December 31, 2011, we had $50.0 million drawn on the Second Lien Credit Agreement.

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In addition to credit facilities, 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 other obligations consisted of the following at September 30, 2012 and December 31, 2011:

	September 30, 2012			December 31, 2011
	($ in Thousands)			($ in Thousands)
Secured Lines of Credit(a)	$	172,000		$	225,000
Capital Leases and Other Obligations(a)		2,399			544
Total Debts		174,399			225,544
Less Current Portion of Long-Term Debt(b)		(1,648	)		(406	)
Total Long-Term Debt	$	172,751		$	225,138

^(a)  The credit facilities require us to make monthly payments of interest on the outstanding balance of loans made under the agreements. The average interest rate on borrowings under our credit facilities for the three and nine months ended September 30, 2012 was approximately 3.9% and 3.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2012 was approximately 3.5% and 3.4%, respectively.

^(b)  Included in Accounts Payable on our Consolidated Balance Sheets.

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, natural gas and natural gas liquids. To mitigate a portion of the exposure to adverse market changes, we enter into commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor on the settlement dates, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling on the settlement dates, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of September 30, 2012, our oil, natural gas and natural gas liquids derivative commodity instruments consisted of fixed rate swap contracts, collars, swaptions, and put options. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly on our Consolidated Statements of Operations under the heading Gain (Loss) on Derivatives, Net.

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 settlement 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 settlement 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. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Swaption agreements provide options to counterparties to extend swaps into subsequent years.

We enter into the majority of our derivative arrangements with four counterparties and have a netting agreement in place. We present our derivatives as gross assets or liabilities on our Consolidated Balance Sheets. 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 counterparties, see Note 5,Concentrations of Credit Risk, to our Consolidated Financial Statements.

We received net payments of $4.3 million and $1.6 million under these commodity derivative instruments during the three-month periods ended September 30, 2012 and 2011, respectively, and received net payments of $13.4 million and $3.8 million during the nine-month periods ended September 30, 2012 and 2011, respectively. Unrealized gains and losses associated with our commodity derivative instruments amounted to unrealized losses of $10.2 million and $8.2 million for the three and nine months ended September 30, 2012, respectively, as compared to unrealized gains of $10.6 million and $9.0 million for the three and nine months ended September 30, 2011, respectively.

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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 nine months ended September 30, 2012 and 2011 ($ in thousands):

	Three Months Ended September 30, 2012								Three Months Ended September 30, 2011
	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	$	0	$	(37	)	$	(37	)	$	0		$	558		$	558
Mark-to-market fair value adjustments		0		(1,455	)		(1,455	)		0			6,562			6,562
Settlement of contracts(a)		0		0			0			(5	)		0			(5	)
Crude Oil Total		0		(1,492	)		(1,492	)		(5	)		7,120			7,115
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0		(2,945	)		(2,945	)		0			(1,142	)		(1,142	)
Mark-to-market fair value adjustments		0		(5,144	)		(5,144	)		0			4,594			4,594
Settlement of contracts(a)		4,119		0			4,119			1,607			0			1,607
Natural Gas Total		4,119		(8,089	)		(3,970	)		1,607			3,452			5,059
Natural Gas Liquids
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0		(214	)		(214	)		0			0			0
Mark-to-market fair value adjustments		0		(372	)		(372	)		0			0			0
Settlement of contracts(a)		155		0			155			0			0			0
Natural Gas Liquids Total		155		(586	)		(431	)		0			0			0
Gain (Loss) on Derivatives, Net	$	4,274	$	(10,167	)	$	(5,893	)	$	1,602		$	10,572		$	12,174

(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.

	Nine Months Ended September 30, 2012									Nine Months Ended September 30, 2011
	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	$	0		$	1,603		$	1,603		$	0		$	1,388		$	1,388
Mark-to-market fair value adjustments		0			464			464			0			4,611			4,611
Settlement of contracts(a)		(287	)		0			(287	)		(648	)		0			(648	)
Crude Oil Total		(287	)		2,067			1,780			(648	)		5,999			5,351
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0			(7,803	)		(7,803	)		0			(3,173	)		(3,173	)
Mark-to-market fair value adjustments		0			(2,989	)		(2,989	)		0			6,146			6,146
Settlement of contracts(a)		13,394			0			13,394			4,463			0			4,463
Natural Gas Total		13,394			(10,792	)		2,602			4,463			2,973			7,436
Natural Gas Liquids
Mark-to-market fair value adjustments		0			558			558			0			0			0
Settlement of contracts(a)		248			0			248			0			0			0
Natural Gas Liquids Total		248			558			806			0			0			0
Gain (Loss) on Derivatives, Net	$	13,355		$	(8,167	)	$	5,188		$	3,815		$	8,972		$	12,787

(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.

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net asset of approximately $7.2 million and a net asset of $15.3 million at September 30, 2012 and December 31, 2011, respectively. Included in the fair value as of September 30, 2012 and December 31, 2011, is a liability of approximately $0.5 million associated with a premium that is due to the counterparty upon settlement of the related contract.

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As of September 30, 2012, we had approximately 85.9%, 77.3% and 27.5% of our current oil production on an annualized basis hedged through 2012, 2013 and 2014, respectively, in addition to 68.2%, 82.4% and 20.5% of our current gas production on an annualized basis hedged through 2012, 2013 and 2014, respectively, and 34.2% of our current natural gas liquids production on an annualized basis hedged through 2012 and 2013. Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2012 consisted of:

Period	Volume	Put Option		Floor		Ceiling		Swap		Fair Market Value ($ in Thousands)
Oil
2012—Collar	150,000 Bbls	$	—	$	68.39	$	111.08	$	—	$	(73	)
2013—Collar	540,000 Bbls		—		72.44		112.56		—		(322	)
2014—Three Way Collar	192,000 Bbls		65.00		80.00		106.25		—		(391	)
	882,000 Bbls									$	(786	)
Natural Gas
2012—Swap	1,440,000 Mcf	$	—	$	—	$	—	$	4.06	$	552
2012—Swaption	150,000 Mcf		—		—		—		5.25		214
2012—Three Way Collar	660,000 Mcf		3.66		4.48		5.13		—		334
2012—Collar	750,000 Mcf		—		4.70		5.89		—		946
2013—Swap	5,970,000 Mcf		—		—		—		3.82		51
2013—Three Way Collar	2,520,000 Mcf		3.35		4.17		4.88		—		697
2013—Collar	3,360,000 Mcf		—		4.77		5.68		—		3,439
2013—Put	2,640,000 Mcf		—		5.00		—		—		2,754	a
2014—Call	1,800,000 Mcf		—		—		5.00		—		(491	)
2014—Three Way Collar	600,000 Mcf		2.75		3.50		4.25		—		(117	)
2014—Swap	1,200,000 Mcf		—		—		—		3.42		(612	)
2014—Collar	1,800,000 Mcf		—		3.51		4.43		—		(365	)
	22,890,000 Mcf									$	7,402
Natural Gas Liquids
2012—Swap	27,000 Bbls	$	—	$	—	$	—	$	43.26	$	112
2013—Swap	108,000 Bbls		—		—		—		43.26		446
	135,000 Bbls										558

^a  Includes liability of approximately $0.5 million for premium due upon settlement of contract.

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The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011 is summarized below ($ in thousands):

	September 30, 2012			December 31, 2011
Short-Term Derivative Assets:
Crude Oil - Collars	$	133		$	0
Natural Gas Liquids - Swaps		446			0
Natural Gas – Swaps		1,946			3,912
Natural Gas – Swaption		214			1,047
Natural Gas – Three Way Collars		945			1,333
Natural Gas – Collars		3,525			4,112
Natural Gas – Putsa		2,066			0
Total Short –Term Derivative Assets	$	9,275		$	10,404
Long-Term Derivative Assets:
Crude Oil – Collars	$	44		$	143
Natural Gas Liquids - Swaps		112			0
Natural Gas – Swaps		345			1,377
Natural Gas – Collars		859			5,690
Natural Gas – Three Way Collars		204			861
Natural Gas – Putsa		689			505
Total Long – Term Derivative Assets	$	2,253		$	8,576
Total Derivative Assets	$	11,528		$	18,980
Short-Term Derivative Liabilities:
Crude Oil – Collars	$	(448	)	$	(2,363	)
Natural Gas – Three Way Collars		(88	)		0
Natural Gas - Swaps		(1,364	)		0
Total Short – Term Derivative Liabilities	$	(1,900	)	$	(2,363	)
Long-Term Derivative Liabilities:
Crude Oil – Three Way Collars	$	(390	)	$	(632	)
Crude Oil – Collars		(125	)		0
Natural Gas - Swaps		(936	)		0
Natural Gas – Three Way Collars		(147	)		0
Natural Gas – Call		(491	)		0
Natural Gas – Collars		(365	)		(643	)
Total Long – Term Derivative Liabilities	$	(2,454	)	$	(1,275	)��
Total Derivative Liabilities	$	(4,354	)	$	(3,638	)

^a Includes liability of approximately $0.5 million for premium due upon settlement of contract.

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. 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. This fair value may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities. There are three levels of fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy 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.

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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 three and nine months ended September 30, 2012, 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 September 30, 2012 Using:
	Total Carrying Value as of September 30, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivative Contracts(a)	$	7,174	$	0	$	7,174	$	0
Asset Retirement Obligations	$	24,085	$	0	$	0	$	24,085
Assets Held for Sale	$	10,439	$	0	$	0	$	10,439

(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 17 of this report.

The value of our oil derivatives are comprised of collar and three way collar contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of September 30, 2012 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of puts, swaps, swaptions, collars and three way collar contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of September 30, 2012 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our natural gas liquids derivatives are comprised of swaps for notional volumes of natural gas liquids contracted at NYMEX Mont Belvieu Propane (“MBP”). The fair values attributable to our natural gas liquids derivative contracts as of September 30, 2012 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for MBP, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. 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 instruments 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; estimated plugging costs; the credit-adjusted risk-free rate to be used; and inflation rates. The most significant inputs used in the determination of asset retirement obligations are the estimated costs to plug and abandon our wells. Significant changes in the estimated cost to plug and abandon our wells can cause significant changes in the fair value measurement of our asset retirement obligations due to the large number of wells that we operate. These inputs are unobservable, and thus result in a Level 3 classification. Refer to Note 2,Asset Retirement Obligation,of our Consolidated Financial Statements for further information on asset retirement obligations, which include a reconciliation of the beginning and ending balances that represent the entirety of our Level 3 fair value measurements.

Assets Held for Sale

We report the fair value of Assets Held for Sale on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of the Assets Held for Sale based on purchase and sale transactions in the immediate region encompassing the assets. The most significant input used in determining the fair value of our Assets Held for Sale is purchase and sale transactions of similar assets in the DJ basin. These transactions are typically analyzed on the basis of cost per net acre. Significant changes to cost per acre

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indicators could change our estimate of fair value based on the number of acres that we have under leasehold. As of September 30, 2012, we had approximately 44,000 net acres under leasehold in the DJ Basin. Refer to Note 3,Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements for further information on our Assets Held for Sale, which includes a narrative of the change in fair value measurements.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:

	September 30, 2012				December 31, 2011
In thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Secured Lines of Credit	$	172,000	$	172,000	$	225,000	$	225,000
Capital Leases and Other Obligations		2,399		2,245		544		511
Total	$	174,399	$	174,245	$	225,544	$	225,511

The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.

The fair value of the capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and an assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases would be classified as Level 3 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

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 September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Income Tax (Expense) Benefit	$	2,131		$	(5,440	)	$	(35,768	)	$	(8,207	)
Effective Tax Rate		51.6	%		30.1	%		38.2	%		32.6	%

For the three and nine months ended September 30, 2012, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to permanent differences state taxes and the reversal of certain valuation allowances that were related to deferred tax assets that we now expect to realize. As of December 31, 2011, we had approximately $15.7 million in tax effected net operating loss carry forwards that we anticipate utilizing to help offset the taxable income recognized during the first nine months of 2012. For the three and nine months ended September 30, 2011, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily to state taxes, which was in part offset by permanent differences, changes to estimated future state rates and state net operating loss carryforward true-ups.

9. CAPITAL STOCK

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of September 30, 2012 and December 31, 2011, we had 52,853,214 and 44,859,220 shares of common stock outstanding, respectively. There were no shares of preferred stock outstanding as of September 30, 2012 and December 31, 2011.

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On February 6, 2012, we completed an underwritten public offering of 8,050,000 shares of our common stock, which included 1,050,000 shares of common stock issued upon the full exercise of the underwriters’ over-allotment option, at a public offering price of $9.25 per share. The net proceeds from the offering were approximately $70.6 million, after deducting underwriting discounts, commissions and estimated offering expenses. We used a portion of the proceeds of the offering to repay a portion of outstanding borrowings under our Senior Credit Facility and used the remaining net proceeds to fund a portion of our capital expenditure program for 2012 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 minimum age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan were $0.2 million and $0.4 million for the three and nine months ended September 30, 2012, respectively, and $0.1 million and $ 0.3 million for the three and nine months ended September 30, 2011, 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.

2007 Long-Term Incentive Plan

We have granted stock options, stock appreciation rights and restricted stock awards to various employees, consultants and non-employee directors under the terms of our 2007 Long-Term Incentive Plan, as amended (the “Plan”). The Plan is administered by the Compensation Committee of our Board of Directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are: selecting participants to receive awards; determining the form, amount and other terms and conditions of awards; interpreting the provisions of the Plan or any award agreement; and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Internal Revenue 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 closing price of our common stock on the NASDAQ Global Market on the date of the grant. All outstanding stock options have been awarded with five or ten year expiration dates 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, again become 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 three and nine months ended September 30, 2012, we did not issue options to purchase shares of our common stock. During the three and nine months ended September 30, 2011, the Compensation Committee awarded options to purchase a total of 0 and 3,500 shares, respectively, of our common stock to one employee. The nonqualified stock options granted 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 each of the first, second and third anniversaries of the grant date. All options will vest and become exercisable upon a “change in control,” as that term is defined in the Plan.

Stock-based compensation expense relating to stock options for the for the three and nine months ended September 30, 2012 was $0.1 million and $0.2 million, respectively, as compared to $0.1 million and $0.6 million for the three and nine months ended September 30, 2011, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. The intrinsic value of stock options exercised for the nine months ended September 30, 2012 was $0.1 million. The total tax benefit for the three and nine months ended September 30, 2012 was negligible. The intrinsic value of stock options exercised for the three and nine months ended September 30, 2011 was $0.3 million. The total tax benefit for the three and nine months ended September 30, 2011 was $0.2 million and $0.3 million, respectively.

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A summary of the status of our issued and outstanding stock options as of September 30, 2012 is as follows:

		Outstanding				Exercisable
Exercise     price		Number Outstanding At 9/30/12		Weighted-Average Exercise Price		Number Exercisable At 9/30/12		Weighted-Average Exercise Price
$	9.99		154,750	$	9.99		154,750	$	9.99
$	9.50		100,000	$	9.50		100,000	$	9.50
$	22.34		30,000	$	22.34		30,000	$	22.34
$	23.28		4,000	$	23.28		4,000	$	23.28
$	19.92		5,000	$	19.92		5,000	$	19.92
$	9.99		21,249	$	9.99		21,249	$	9.99
$	9.99		37,500	$	9.99		37,500	$	9.99
$	5.04		46,041	$	5.04		46,041	$	5.04
$	10.42		29,548	$	10.42		19,696	$	10.42
$	13.01		18,526	$	13.01		6,175	$	13.01
$	12.50		19,139	$	12.50		6,380	$	12.50
$	11.87		3,500	$	11.87		1,167	$	11.87
$	13.19		50,000	$	13.19		0	$	0
			519,253	$	10.91		431,958	$	10.55

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at September 30, 2012 were 4.9 years and $1.6 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at September 30, 2012 were 5.3 years and $1.5 million, respectively. As of September 30, 2012, unrecognized compensation expense related to stock options totaled approximately $0.3 million, which will be recognized over a weighted average period of 1.8 years.

Restricted Stock and Phantom Stock Awards

During the nine-month period ended September 30, 2012, the Compensation Committee issued an aggregate of 75,621 shares of restricted common stock to 20 employees. During the nine-month period ended September 30, 2011, the Compensation Committee issued an aggregate of 164,649 shares of restricted stock to 12 employees and five non-employee directors. In addition, during the first nine months of 2011, the Compensation Committee issued 16,235 phantom stock awards to five directors, which can only be settled in cash and have not been included in our outstanding shares of common stock. The shares granted under these awards are subject to time vesting, and in some cases, performance-based vesting. The performance-based vesting is generally dictated by cumulative three-year targets for consolidated company production and discretionary cash flow per weighted-average outstanding share. 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 and are included in the Plan or the individual awards, as applicable. 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.

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 $1.2 million and $2.0 million for the three and nine-month periods ended September 30, 2012, respectively, and $0.2 million and $0.8 million for the three and nine-month periods ended September 30, 2011, respectively. As of September 30, 2012, total unrecognized compensation cost related to restricted common stock grants was approximately $3.2 million, which will be recognized over a weighted average period of 2.0 years.

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A summary of the restricted stock activity for the nine months ended September 30, 2012 is as follows:

	Number of Shares			Weighted Average  Grant Date Fair Value
Restricted stock awards, as of December 31, 2011		1,229,826		$	12.11
Awards		75,621			10.95
Forfeitures		(146,174	)		12.11
Vested		(70,750	)		2.05
Restricted stock awards, as of September 30, 2012		1,088,523		$	12.69

A summary of the phantom stock activity for the nine months ended September 30, 2012 is as follows:

	Number of Shares		Weighted Average  Grant Date Fair Value
Phantom stock awards, as of December 31, 2011		30,975	$	12.91
Awards		0		0
Forfeitures		0		0
Restrictions released		0		0
Phantom stock awards, as of September 30, 2012		30,975	$	12.91

11. COMMITMENTS AND CONTINGENCIES

Legal Reserves

We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.

The accrual of reserves for legal matters is included in Accrued Expenses on our 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, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently 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 our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

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

In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease together with an order for payment and related documents to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them. The plaintiffs sought a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees.

We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the Cardinale case was dismissed with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs have appealed the dismissal and the parties have filed briefs and responses with respect to the appeal; however, as of September 30, 2012, no date had been set for the appeal proceedings.

In July 2012, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contains the same claims as those set forth in the Cardinale case. We have not yet been served with a complaint in the Meeker case, but we

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believe the claims will also mirror those made in the Cardinale and Billotte cases. It is our understanding that these two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case. Proceedings in both the Billotte and Meeker cases have been stayed pending the outcome of the appeal in the Cardinale case.

We intend to vigorously defend against each of these claims. Due to the dismissal of the Cardinale case and the uncertainty of the outcome of the appeal, and the similarity of the claims for the Billotte and Meeker cases, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome for any of these cases or provide an estimate of potential losses.

Acreage Bonus Payments

At September 30, 2012, we had installment payment commitments on mineral interests that were previously leased in the amount of $0.1 million. All of these commitments are expected to be paid in 2012 and have been classified as Accrued Expenses on our Consolidated Balance Sheet. At December 31, 2011, our liability for installment payment commitments totaled approximately $1.2 million, which was classified as Accrued Expenses on our Consolidated Balance Sheet.

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. As of September 30, 2012, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

At September 30, 2012, we had posted $0.8 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of September 30, 2012, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Our rent expense for the three months ended September 30, 2012 was negligible while rent expense for the nine months ended September 30, 2012 was approximately $0.5 million as compared to $0.1 million and $0.3 million for the three and nine months ended September 30, 2011, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):

2012	$	148
2013		676
2014		524
2015		464
2016		420
Thereafter		420
Total	$	2,652

Capacity Reservation

In conjunction with our sale of Keystone Midstream Services, LLC (“Keystone Midstream”) (see Note 15,Equity Method Investments,to our Consolidated Financial Statements), we entered into a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned and operated by MarkWest to process our natural gas production. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $1.3 million for the remainder of 2012, $6.1 million for 2013, $10.4 million for 2014, $13.0 million for 2015, $14.6 million for 2016 and approximately $129.8 million thereafter. During the three and nine months ended September 30, 2012, we incurred capacity reservation charges of $0.1 million and $0.2 million, respectively, which is consistent with our estimated working interest in this project area. During the three and nine months ended September 30, 2011, we incurred charges of approximately $0 and $0.1 million, respectively, in relation to the capacity reservation. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations. We expect our capacity reservation charges to be negligible in the future as we place additional wells into service.

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Operational Commitments

Pursuant to agreements reached during the fourth quarter of 2010 and the first quarter of 2011, and amended during the third quarter of 2012, we have contracted drilling rig services on two rigs to support our Appalachian Basin operations. The minimum cost to retain these rigs would require payments of approximately $0.8 million in 2012, $3.0 million in 2013, $3.0 million in 2014 and $0.8 million in 2015, which is consistent with our estimated working interest in this project area. In addition, during the first quarter of 2011, we engaged contract completion services in the Appalachian Basin. The minimum cost to retain the completion services is approximately $2.1 million in 2012, $8.4 million in 2013 and $2.1 million in 2014, which is consistent with our estimated working interest in this project area.

Natural Gas Gathering, Processing and Sales Agreement

During the third quarter of 2011, we entered into a natural gas sales agreement with BP Energy Company (“BP Energy”), under which we have agreed to supply natural gas to BP Energy at certain delivery points in Pennsylvania with a termination date expected to be December 31, 2022, unless terminated earlier under certain conditions specified in the sales agreement. During the term of the sales agreement, we are obligated to provide to BP Energy, and BP Energy is obligated to purchase from us, a minimum monthly volume of natural gas equivalent to 17,500 MMBtu of natural gas per day from March 1, 2012 to December 31, 2012 and 59,500 MMBtu per day after January 1, 2013. On all volumes delivered, and on any shortfalls between volumes delivered and the minimum monthly quantity, we are obligated to pay a marketing fee and a demand charge. In connection with the entry into the sales agreement, we concurrently entered into a guaranty agreement whereby we have guaranteed the payment of obligations under the sales agreement up to a maximum of $50.0 million.

During the fourth quarter of 2011, we entered into gathering and processing agreements with Dominion East Ohio (“Dominion East”) and Dominion Natrium, LLC (“Dominion Natrium”), respectively, to transport and process anticipated natural gas and natural gas liquid production in Ohio. Under the gathering agreement, we have agreed to supply natural gas at certain delivery points in Ohio for a 10-year primary term, which is anticipated to begin on October 1, 2012. During the term of the gathering agreement, Dominion East is obligated to transport a maximum of 15,000 mcf per day and we are obligated to pay a fee based on the volumes transported. Under the processing agreement, we have agreed to supply natural gas at Dominion Natrium’s processing and fractionation facility in Natrium, West Virginia for a 10-year primary term, which is anticipated to begin in December 2012. During the term of the processing agreement, Dominion Natrium is obligated to process a maximum of 15,000 mcf per day and we are obligated to pay a reservation fee.

In coordination with the aforementioned gathering and processing agreements, we have entered into an additional natural gas sales agreement with BP Energy, where we are obligated to sell, and BP Energy is obligated to purchase, 14,000 MMBtu per day of natural gas, for which we will pay a marketing fee and demand charge. The effective date of the sales agreement is expected to be no sooner than November 1, 2014, based on the estimated completion of the construction of the gathering and processing facilities, and will last until December 31, 2022.

For the three and nine-month periods ended September 30, 2012, we incurred expenses related to marketing our natural gas, firm transportation and processing and gathering fees of $2.6 million and $5.7 million, respectively, as compared to $1.4 million and $3.2 million for the three and nine-month periods ended September 30, 2011, respectively.

Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows ($ in thousands):

	BP Energy		Dominion East(a)		Dominion Natrium(a)		Total
2012	$	186	$	345	$	195	$	726
2013		2,531		1,369		2,300		6,200
2014		2,673		1,369		2,300		6,342
2015		3,382		1,369		2,300		7,051
2016		3,382		1,369		2,300		7,051
Thereafter		21,143		7,868		13,602		42,613
Total	$	33,297	$	13,689	$	22,997	$	69,983

(a) Assumes 100% working interest; actual working interest could be materially different as drilling units are formed.

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Drilling Commitments

During the first quarter of 2012, we entered into a drill-to-earn agreement with MFC Drilling, Inc. (“MFC”). Under the terms and conditions of the agreement, we will acquire at a minimum, through a drill-to-earn structure, a 62.5% working interest in approximately 4,510 acres in Belmont, Guernsey and Noble Counties, Ohio. The agreement provides that in order for us to earn the 62.5% working interest, we will bear the cost for our 62.5% working interest and 100% of the 15% working interest of MFC until such time that we have met the $14.1 million drilling carry obligation. As of September 30, 2012, the remaining drilling carry obligation balance was approximately $13.2 million.

In addition to the drilling carry obligation, we are required to meet drilling commitments, the first of which is to drill three wells to test the Utica Shale formation and complete one of these wells no later than December 31, 2012, for a total estimated commitment of $11.4 million (the “Initial Drilling Commitment”). As of September 30, 2012, all three commitment wells for the current year were in various stages of drilling and completion. Amounts incurred toward the attainment of the drilling commitments are credited towards the drilling carry obligation. Subsequently, we are to commence the drilling of at least three Utica Shale wells by November 15 of each year until the carry obligation has been satisfied, with credits given to additional wells drilled beyond the annual commitment. We currently estimate the commitment for each well drilled and completed for our working interest and that of MFC to be approximately $8.0 million to $9.0 million. Upon the fulfillment of the Initial Drilling Commitment, we have until the earlier of (i) six months from the first date of sales and (ii) June 15, 2013 to terminate the agreement. Should we not comply with the drilling commitments or terminate the agreement outside of the aforementioned termination parameters, we would be responsible for payment of the remaining drilling carry obligation at that time.

Pennsylvania Impact Fee

During the first quarter of 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:

	< $2.25a		$2.26 -  $2.99a		$3.00 -  $4.99a		$5.00 -  $5.99a		> $5.99a
Year One	$	40,000	$	45,000	$	50,000	$	55,000	$	60,000
Year Two	$	30,000	$	35,000	$	40,000	$	45,000	$	55,000
Year Three	$	25,000	$	30,000	$	30,000	$	40,000	$	50,000
Year 4 – 10	$	10,000	$	15,000	$	20,000	$	20,000	$	20,000
Year 11 – 15	$	5,000	$	5,000	$	10,000	$	10,000	$	10,000

^a  Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

For the three and nine months ended September 30, 2012, we recorded expenses of $0.7 million and $4.6 million, respectively. Of the expenses incurred to date, approximately $2.8 million is related to wells spud prior to 2012, for which the first year fee was due on September 1, 2012. The current portion of the impact fees will be accrued evenly throughout the year beginning on the date a well has been spud, or on January 1 if the well was spud in the prior year. We are recording the accrual of the impact fees as Production and Lease Operating Expense.

Other

In addition to the Asset Retirement Obligation discussed in Note 2,Asset Retirement Obligation, 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 totaled $0.3 million at September 30, 2012 and December 31, 2011 and are included in Other Liabilities on our Consolidated Balance Sheets.

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12. 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, excluding restricted stock with performance-based vesting criteria. Diluted income per common share includes the assumed exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market based, provided that the hypothetical effect is not anti-dilutive. Stock options to purchase 519,253 shares of common stock for the three-month period ended September 30, 2012 were outstanding but not included in the computation of diluted net income per share due to our net loss from continuing operations, which would result in an anti-dilutive effect. Stock options to purchase 456,140 shares of common stock for the nine-month period ended September 30, 2012, respectively, 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, which has anti-dilutive effect on the computation. Due to our net loss from continuing operations for the three and nine-month periods ended September 30, 2011, we excluded all 682,527 outstanding stock options 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 September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Numerator:
Net Income (Loss) From Continuing Operations, Less Noncontrolling Interests	$	(1,935	)	$	12,622		$	57,765		$	16,944
Net Loss From Discontinued Operations		(258	)		(20,812	)		(8,662	)		(29,195	)
Net Income (Loss)	$	(2,193	)	$	(8,190	)	$	49,103		$	(12,251	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		52,036			43,951			51,120			43,897
Effect of Dilutive Securities:
Employee Stock Options		0			86			63			95
Employee Performance-Based Restricted Stock Awards		769			347			835			456
Weighted Average Common Shares Outstanding - Diluted		52,805			44,384			52,018			44,448
Earnings per Common Share:
Basic — Net Income (Loss) From Continuing Operations	$	(0.04	)	$	0.29		$	1.13		$	0.39
— Net Loss From Discontinued Operations		0.00			(0.47	)		(0.17	)		(0.67	)
— Net Income (Loss)	$	(0.04	)	$	(0.18	)	$	0.96		$	(0.28	)
Diluted — Net Income (Loss) From Continuing Operations	$	(0.04	)	$	0.28		$	1.11		$	0.38
— Net Loss From Discontinued Operations		0.00			(0.47	)		(0.17	)		(0.66	)
— Net Income (Loss)	$	(0.04	)	$	(0.19	)	$	0.94		$	(0.28	)

13. BUSINESS SEGMENT INFORMATION

We have two business segments: (1) exploration and production and (2) field services. These two segments represent our two main business units, each offering different products and services. Our exploration and production segment engages in the exploration, acquisition, development and production of oil and natural gas, including our activities in the Illinois and Appalachian Basins. Our field services segment includes management of water sourcing, water transfer and water disposal services.

We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. Summarized financial information concerning our segments is shown in the following table (in thousands):

	Exploration and Production			Field Services			Intercompany Eliminations			Consolidated Total
Three Months EndedSeptember 30, 2012
Revenues	$	34,759		$	4,839		$	(669	)	$	38,929
Inter-Segment Revenues		0			(669	)		669			0
Total Revenues	$	34,759		$	4,170		$	0		$	38,929
Income (Loss) From Continuing Operation, Before Income Taxes	$	(4,631	)	$	934		$	(176	)	$	(3,873	)
Three Months EndedSeptember 30, 2011
Revenues	$	30,313		$	918		$	(476	)	$	30,755
Inter-Segment Revenues		0			(476	)		476			0
Total Revenues	$	30,313		$	442		$	0		$	30,755
Income (Loss) From Continuing Operation, Before Income Taxes	$	18,339		$	220		$	(453	)	$	18,106
Nine Months Ended September 30, 2012
Revenues	$	94,030		$	10,681		$	(1,691	)	$	103,020
Inter-Segment Revenues		0			(1,691	)		1,691			0
Total Revenues	$	94,030		$	8,990		$	0		$	103,020
Income (Loss) From Continuing Operation, Before Income Taxes	$	91,825		$	2,673		$	(449	)	$	94,049
Nine Months Ended September 30, 2011
Revenues	$	81,245		$	2,438		$	(759	)	$	82,924
Inter-Segment Revenues		0			(759	)		759			0
Total Revenues	$	81,245		$	1,679		$	0		$	82,924
Income (Loss) From Continuing Operation, Before Income Taxes	$	25,925		$	(72	)	$	(716	)	$	25,137
As of September 30, 2012
Total Assets	$	694,079		$	11,583		$	(6,126	)	$	699,536
As of December 31, 2011
Total Assets	$	600,071		$	7,143		$	(5,663	)	$	601,551

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14. CONSOLIDATED SUBSIDIARIES

Water Solutions Holdings

In November 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions”) for the purpose of acquiring, managing and operating water treatment, disposal and transportation facilities that are designed to treat, dispose or transport brine and fresh waters used and produced in oil and gas well development activities. The members of Water Solutions 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.

We account for the 20% equity interest in Water Solutions that is owned by Sand Hills as a noncontrolling interest. As of September 30, 2012 and December 31, 2011, there was no recourse to our general credit. Water Solutions is financed through cash contributions from its members and a credit facility for which $0.7 million was drawn as of September 30, 2012. There were no cash contributions during the first nine months of 2012 and cash contributions during the first nine months of 2011 were negligible. The carrying amount and classification of Water Solutions’ assets and liabilities as of September 30, 2012 and December 31, 2011 were as follows, with no restrictions to use certain assets to settle associated liabilities:

	September 30, 2012 (in  thousands)			December 31, 2011 (in  thousands)
ASSETS
Cash and Cash Equivalents	$	345		$	374
Accounts Receivable		3,862			877
Inventory, Prepaid Expenses and Other		37			11
Other Property and Equipment		2,860			561
Wells and Facilities in Progress		19			134
Accumulated Depreciation, Depletion and Amortization		(318	)		(75	)
Deferred Financing Costs and Other Assets - Net		213			192
Total Assets	$	7,018		$	2,074
LIABILITIES
Accounts Payable	$	1,444		$	481
Accrued Expenses		1,437			119
Senior Secured Line of Credit and Long-Term Debt		666			100
Total Liabilities	$	3,547		$	700

NorthStar #3, LLC

In August 2011, our wholly owned subsidiary, R.E. Gas Development, LLC (“R.E. Gas”) and NorthStar Water Management (“NorthStar”) formed NorthStar #3, LLC (“NorthStar #3”) to construct, own and operate a water disposal well in Mahoning County, Ohio. At September 30, 2012, R.E. Gas owned a 51% membership interest in NorthStar #3, and the remaining 49% membership interest was owned by NorthStar, which also serves as the operator of the entity. To supplement the operations of NorthStar #3, the entity entered into a promissory note with us. As of September 30, 2012, the amount owed to us under the promissory note was $4.6 million. Due to its insufficient equity to fund operations, NorthStar #3 has been classified as a variable interest entity (“VIE”).

A VIE is an entity that by design has insufficient equity to permit it to finance its activities without additional subordinated financial support or equity holders that lack the characteristics of a controlling financial interest. Based on these factors, we have determined NorthStar #3 to be a VIE.

We are considered the primary beneficiary of the entity and have consolidated its financial results in our Consolidated Financial Statements. To be considered the primary beneficiary, a member must have the power to direct the activities that most significantly impact the entity’s performance and have a significant variable interest that carries with it the obligation to absorb the losses or the right to receive benefits. The activities that most significantly impact the entity’s economic performance relate to the drilling of a successful disposal well with sufficient capacity and the ongoing operation of the well. Per the membership agreement, we hold a first right of refusal on all capacity rights for the disposal well, giving us the ability to make decisions regarding the operation and capacity of the well based on market conditions and, thus, the ability to direct the activities that most significantly impact the economic performance of the entity. We hold a significant variable interest in the entity in the form of our 51% membership interest and the $4.6 million promissory note. We have no recourse to recover the amount of the promissory note in the event that the disposal well is unsuccessful, leaving us with the obligation to absorb the losses. Upon success of the disposal well, we will initially have the right to approximately 87.3% of the available cash at the end of the period which covers the repayment of the note and our membership interest.

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The carrying amount and classifications of NorthStar #3 assets and liabilities as of September 30, 2012 and December 31, 2011 are as follows, with no restrictions or obligations to use certain assets to settle associated liabilities:

	September 30, 2012 (in thousands)		December 31, 2011 (in  thousands)
ASSETS
Cash and Cash Equivalents	$	14	$	10
Wells and Facilities in Progress		4,552		5,059
Total Assets	$	4,566	$	5,069
LIABILITIES
Accounts Payable	$	0	$	134
Note Payable		4,631		4,935
Total Liabilities	$	4,631	$	5,069

15. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

We own a 40% non-operating interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our Appalachian Basin operations. We recorded our investment in RW Gathering of approximately $17.2 million and $15.7 million as of September 30, 2012 and December 31, 2011, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During the first nine months of 2012, we contributed approximately $2.0 million in cash to RW Gathering to support current pipeline and gathering line construction, compared with $7.9 million for the same period in 2011. RW Gathering recorded net losses from continuing operations of $0.4 million and $1.3 million for the three and nine months ended September 30, 2012, respectively, as compared to losses of $0.3 million and $0.6 million for the three and nine months ended September 30, 2011, respectively. The losses incurred were due to taxes, and DD&A. Our share of the net loss is recorded on the Statements of Operations as Gain (Loss) on Equity Method Investments.

During the three and nine months ended September 30, 2012, we incurred approximately $0.2 million and $0.7 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC, as compared to $0.3 million and $0.6 million for the same periods in 2011. 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 September 30, 2012 and December 31, 2011, there were no receivables due from RW Gathering to us.

Keystone Midstream Services, LLC

On May 29, 2012, we closed the sale of our ownership in Keystone Midstream, which we had accounted for as an equity method investment. The base consideration for the sale was $483.2 million after adjustments for closing cash, working capital and outstanding debt. Our net proceeds at closing totaled $121.4 million, net of $3.3 million for our share of transactional costs which were recorded as Gain (Loss) on Equity Method Investments on our Consolidated Statement of Operations. During the three months ended September 30, 2012, we recorded $0.5 million of post closing settlement charges that we expect to incur, effectively decreasing our net proceeds to approximately $120.9 million. We have used the proceeds to pay down amounts outstanding under our Senior Credit Facility and for working capital. The amount received at closing excluded approximately $14.3 million to be held in escrow and paid out over the course of the next twelve months. We will recognize the escrow amount in income as it is received. Also included in the proceeds at closing was approximately $3.8 million funded by other sellers in the transaction as consideration for our entry into an amendment to one of our gas gathering, compression and processing agreements. This consideration is primarily recorded as Other Deposits and Liabilities on our Consolidated Balance Sheet and will be recognized in earnings over the term of the gas gathering, compression and processing agreement. We recognized a gain on the sale of our investment in Keystone Midstream, including the post-closing adjustment of $0.5 million, of approximately $92.2 million, which was recorded as Other Income (Expense) in our Consolidated Statement of Operations.

Prior to its sale on May 29, 2012, we owned a 28% non-operating interest in Keystone Midstream, which was a midstream joint venture focused on building, owning and operating high pressure gathering systems and cryogenic gas processing plants in Butler County, Pennsylvania. We recorded our investment in Keystone Midstream, which was $26.0 million as of December 31, 2011, on our Consolidated Balance Sheets as Equity Method Investments. During the first nine months of 2012 and 2011, we contributed approximately $2.1 million and $11.2 million, respectively, to Keystone Midstream primarily to support the construction of the cryogenic gas processing plants. Keystone Midstream recorded net losses from operations of $11.5 million for the year-to-date period

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ending on the date of sale and net income of $0.7 million and $0.2 million for the three and nine months ended September 30, 2011, respectively. Our share of income and losses is recorded on the Statements of Operations as Gain (Loss) on Equity Method Investments.

During the period from April 1, 2012 through May 29, 2012 and January 1, 2012 through May 29, 2012, we incurred approximately $0.9 million and $2.2 million, respectively, in transportation, processing and capacity reservation expenses that were charged to us by Keystone Midstream, as compared to $1.4 million and $3.3 million for the three and nine months ended September 30, 2011, respectively. As of September 30, 2012 and December 31, 2011, there was a negligible amount due from us to Keystone Midstream for gas processing services provided during the respective periods.

16. IMPAIRMENT EXPENSE

For the three and nine months ended September 30, 2012, we incurred approximately $0.3 million and $3.4 million in impairment expenses, respectively, as compared to $2.4 million and $2.9 million for the three and nine months ended September 30, 2011, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first nine months of 2012 is primarily related to the lack of development plans on several leases in Westmoreland and Clearfield County, Pennsylvania, which are non-operated dry gas regions of the Marcellus Shale. As of September 30, 2012, we continued to carry the costs of undeveloped properties of approximately $159.8 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans. The impairment expense incurred during the three and nine-month period ended September 30, 2011, was related to permitting and engineering costs related to a water purification project and Butler County, Pennsylvania refrigeration plant inventory that was abandoned.

17. EXPLORATION EXPENSE

For the three and nine months ended September 30, 2012, we incurred approximately $1.2 million and $3.5 million in exploration expenses, respectively, as compared to $0.3 million and $2.2 million for the same periods in 2011. Approximately $3.2 million of the expense incurred in 2012 was due to geological and geophysical type expenditures and delay rental payments primarily associated with leases in the Appalachian Basin. An additional $0.3 million related to the plugging of two exploratory Marcellus Shale wells that were spud during 2011 in Butler County, Pennsylvania. Minimal drilling was completed on these wells before a strategic decision was made to abandon the well sites and defer capital to other leases in the development plan and hold the acreage by production. The expenses incurred in 2011 were due to geological and geophysical type expenditures and delay rental payments primarily associated with leases in the Appalachian Basin.

18. SUBSEQUENT EVENTS

DJ Basin

During October 2012, we sold 100% of our acreage holdings in the states of Nebraska and Colorado for proceeds of approximately $3.6 million. The carrying value of these holdings as of September 30, 2012 was approximately $1.3 million and was classified as Assets Held for Sale on our Consolidated Balance Sheet. Subsequent to the sale of these holdings, approximately $9.1 million in carrying value remains on our Consolidated Balance Sheet and classified as Assets Held for Sale for acreage holdings in the state of Wyoming.

Ethane Transportation Agreement

During October 2012, we entered into an ethane transportation agreement with Enterprise Liquids Pipeline LLC (“Enterprise”) to transport ethane produced in our Butler County, Pennsylvania operated area from certain delivery points to a natural gas storage complex at Mont Belvieu in the state of Texas where it will ultimately be marketed and sold. During the term of the agreement we are obligated to provide from 3,000 barrels of ethane per day, at a minimum, to 11,000 barrels of ethane per day, at a maximum, and pay a fee for any shortfalls of these volumes. The term of the agreement is expected to begin in July 2014 and ending in June 2029. In the event that we do not provide any ethane for transportation, we may be obligated to pay approximately $0 in 2012, $0 in 2013, $3.6 million in 2014, $10.7 million in 2015, $17.8 million in 2016 and $324.3 million thereafter. In connection with the entry into the transportation agreement, we concurrently entered into a guaranty agreement whereby we have guaranteed the payment of obligations under the sales agreement up to a maximum of $356.4 million.

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

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2011 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming, Colorado and Nebraska. Pursuant to the rules for discontinued operations, these assets were classified as Assets Held for Sale on our Consolidated Balance Sheets and the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations. Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations.

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 September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
Production:
Oil and Condensate (Bbls)		182,759		179,915		524,149		517,923
Natural Gas (Mcf)		4,865,953		2,583,768		13,191,301		5,768,163
Natural Gas Liquids (Bbls)		96,610		59,869		236,570		136,876
Total (Mcfe)(a)		6,542,167		4,022,472		17,755,615		9,696,957
Average daily production:
Oil and Condensate (Bbls)		1,987		1,956		1,913		1,897
Natural Gas (Mcf)		52,891		28,084		48,143		21,129
Natural Gas Liquids (Bbls)		1,050		651		863		501
Total (Mcfe)(a)		71,111		43,723		64,802		35,520
Average sales price: (b)
Oil and Condensate (per Bbl)	$	89.00	$	86.15	$	92.70	$	91.81
Natural Gas (per Mcf)	$	2.98	$	4.45	$	2.72	$	4.55
Natural Gas Liquids (per Bbl)	$	40.95	$	54.69	$	39.69	$	53.48
Total (per Mcfe)(a)	$	5.31	$	7.52	$	5.29	$	8.36
Average NYMEX prices(c):
Oil (per Bbl)	$	92.32	$	89.55	$	96.23	$	95.42
Natural Gas (per Mcf)	$	2.89	$	4.06	$	2.59	$	4.21

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

(b) Does not include the effects of cash settled derivatives.

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

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	Production and Revenue by Basin
	For Three Months Ended September 30,				For Nine Months Ended September 30,
	2012		2011		2012		2011
Appalachian
Revenues – Natural Gas(a)	$	14,491,897	$	11,484,698	$	35,917,200	$	26,218,329
Volumes (Mcf)		4,865,953		2,583,768		13,191,301		5,768,163
Average Price	$	2.98	$	4.44	$	2.72	$	4.55
Revenues – Condensate(a)	$	341,243	$	35,491	$	442,835	$	51,673
Volumes (Bbl)		4,083		478		5,386		673
Average Price	$	83.58	$	74.25	$	82.22	$	76.78
Revenues – Natural Gas Liquids(a)	$	3,955,708	$	3,274,197	$	9,389,150	$	7,320,352
Volumes (Bbl)		96,610		59,869		236,570		136,876
Average Price	$	40.95	$	54.69	$	39.69	$	53.48
Average Production Cost per Mcfe (b)	$	0.91	$	1.19	$	1.04	$	1.24
Illinois
Revenues – Oil(a)	$	15,922,285	$	15,464,384	$	48,143,366	$	47,496,605
Volumes (Bbl)		178,676		179,436		518,764		517,250
Average Price	$	89.11	$	86.18	$	92.80	$	91.83
Average Production Cost per Bbl(c)	$	27.52	$	29.75	$	31.00	$	29.31

(a) Does not include the effects of cash settled derivatives.

(b) For the nine months ended September 30, 2012, excludes retroactive accrual of Pennsylvania Impact Fee, which equates to approximately $0.15 per Mcfe.

(c) Excludes ad valorem and severance taxes.

	Other Performance Measurements From Continuing Operations
	For Three Months  Ended September 30,				For Nine Months  Ended September 30,
	2012		2011		2012		2011
EBITDAX (in thousands) (a)	$	22,815	$	19,117	$	62,363	$	44,713
LOE per Mcfe(b)	$	1.72	$	2.23	$	1.79	$	2.48
G&A per Mcfe	$	1.05	$	1.11	$	1.02	$	1.92

(a) EBITDAX is a non-GAAP measure. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

(b) For the nine months ended September 30, 2012, excludes retroactive accrual of Pennsylvania Impact Fee, which equates to approximately $0.15 per Mcfe.

General Overview

Operating revenue for the three and nine months ended September 30, 2012 increased 26.6% and 24.2% when compared to the same periods in 2011. In our Butler County, Pennsylvania operated area during June 2012, our midstream provider put into service a new cryogenic gas processing plant (the “Bluestone Plant”) which added to our existing production and processing capacity in the region. The additional processing capacity largely contributed to an increase in our Appalachian Basin production of 85.7% for the three months ended September 30, 2012 as compared to the same period in 2011 and 122.1% for the nine months ended September 30, 2012 as compared to the same period in 2011. Also adding to our increase in production in the Appalachian Basin is our continued drilling success in the region, which has now expanded into Ohio with our first successful Utica Shale well placed in service during the third quarter of 2012. Production in the Illinois Basin has remained flat for the three and nine-month periods ended September 30, 2012

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when compared to the same periods in 2011. This increase in total company production was offset by the current downturn in commodity prices where our realized average sales price for natural gas decreased 33.0% and 40.2% for the three and nine months ended September 30, 2012, respectively, when compared to the same periods in 2011 and our realized average sales price for natural gas liquids decreased 25.1% and 25.8% for the three and nine months ended September 30, 2012, respectively when compared to the same periods in 2011.

Operating expenses increased $10.9 million for the three-month period ended September 30, 2012, as compared to the same period in 2011 and $29.6 million for the nine-month period ended September 30, 2012, as compared to the same period in 2011. Operating expenses primarily comprise: Production and Lease Operating Expenses, G&A Expenses, Loss on Disposal of Assets, Exploration Expenses, Impairment Expense, DD&A Expenses and Field Operating Expenses. The increases in operating expenses were largely to higher DD&A Expenses, G&A Expenses, Field Operating Expenses and Production and Lease Operating Expenses.

The increase in Production and Lease Operating Expenses for the three and nine months ended September 30, 2012 as compared to the same period in 2011 is commensurate with the increase in producing wells in the Appalachian Basin as they relate to variable type costs such as compression, processing and gathering. Additionally, the Commonwealth of Pennsylvania instituted a natural gas impact fee during the first quarter of 2012, which accounted for approximately $0.7 million and $4.6 million in expense for the three and nine month periods ended September 30, 2012, respectively. The period over period increase in DD&A Expenses is consistent with the growth in our asset base, reserves and production since the comparable periods of 2011. The increase in our G&A Expenses during the three month period ended September 30, 2012 was affected by a number of factors including the growth of our Appalachian Basin operations and our corporate headquarters. Field Services Operating expenses have increased for the three and nine month periods ended September 30, 2012 when compared to the same periods in 2011 due to the overall growth of our Field Services operating segment. This segment consists of our water sourcing, transfer and disposal activities, which began in late 2009. The higher demand for these services has increased commensurately with the activity of operators in the Appalachian Basin pursuing the Marcellus and Utica Shale plays.

Pennsylvania Impact Fee

During the first quarter of 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas (the “Pennsylvania Impact Fee”). The fee will be imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:

	< $2.25a		$2.26 -  $2.99a		$3.00 -  $4.99a		$5.00 -  $5.99a		>$5.99a
Year One	$	40,000	$	45,000	$	50,000	$	55,000	$	60,000
Year Two	$	30,000	$	35,000	$	40,000	$	45,000	$	55,000
Year Three	$	25,000	$	30,000	$	30,000	$	40,000	$	50,000
Year 4 – 10	$	10,000	$	15,000	$	20,000	$	20,000	$	20,000
Year 11 – 15	$	5,000	$	5,000	$	10,000	$	10,000	$	10,000

^a  Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

For wells spud prior to 2012, the first year fee (considered to be 2011) was due on September 1, 2012. Expenses for the current portion of the impact fees totaled approximately $0.7 million and $4.6 million for the three and nine months ended September 30, 2012, respectively. The impact fees related to 2012 will be accrued evenly throughout the year beginning on the date a well is spud. We are recording the accrual of the Pennsylvania Impact Fee as Production and Lease Operating Expense.

EBITDAX (Non-GAAP)

EBITDAX (Non-GAAP) from continuing operations increased approximately $3.7 million to $22.8 million for the three-month period ended September 30, 2012 as compared to the same period in 2011. For the nine month-period ended September 30, 2012, EBITDAX increased $17.7 million to $62.4 million, as compared to the same period in 2011. The increase in EBITDAX can be primarily attributed to higher natural gas and natural gas liquids production, resulting in increased operating revenues, and greater income from the settlement of derivative contracts. These increases were partially offset by an increase in operating expenses, particularly the retroactive portion of the Pennsylvania Impact Fee during the nine-month period ended September 30, 2012. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

31

LOE per Mcfe

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 to $1.72 for the three months ended September 30, 2012 as compared to $2.23 for the same period in 2011 and decreased to $1.79 for the nine months ended September 30, 2012, as compared to $2.48 during the nine months ended September 30, 2011. As we continue to develop our non-proved properties, such as the Marcellus Shale, which have a lower operating cost, we believe this metric will continue to decrease on a per unit basis. For comparative purposes, we have excluded approximately $0.15 per Mcfe from the first nine months of 2012 lifting cost, which represents the retroactive portion of the Pennsylvania impact fee.

G&A Expenses per Mcfe

Our general and administrative expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe decreased to approximately $1.05 for the three-month period ended September 30, 2012, as compared to $1.11 for the same period in 2011 and decreased to approximately $1.02 for the nine-month period ended September 30, 2012, as compared to $1.92 for the nine-month period ended September 30, 2011. As we continue to develop our non-proved properties, we believe this metric will continue to decrease on a per unit basis.

32

Comparison of the Three Months Ended September 30, 2012 to the Three Months Ended September 30, 2011.

Oil and gas revenue for the three-month periods ended September 30, 2012 and 2011 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:

	For Three Months Ended September 30,
	2012		2011			Change			%
Oil and Gas Revenues:
Oil and condensate sales revenue	$	16,263	$	15,500		$	763			4.9	%
Oil derivatives realized (a)	$	—	$	(5	)	$	5			100.0	%
Total oil and condensate revenue and derivatives realized	$	16,263	$	15,495		$	768			5.0	%
Gas sales revenue	$	14,492	$	11,485		$	3,007			26.2	%
Gas derivatives realized (a)	$	4,119	$	1,607		$	2,512			156.3	%
Total gas revenue and derivatives realized	$	18,611	$	13,092		$	5,519			42.2	%
Natural gas liquid revenue	$	3,956	$	3,274		$	682			20.8	%
Natural gas liquid derivatives realized (a)	$	155	$	—		$	155			100.0	%
Total natural gas liquid revenue and derivatives realized (a)	$	4,111	$	3,274		$	837			25.6	%
Consolidated sales	$	34,711	$	30,259		$	4,452			14.7	%
Consolidated derivatives realized (a)	$	4,274	$	1,602		$	2,672			166.8	%
Total oil and gas revenue and derivatives realized	$	38,985	$	31,861		$	7,124			22.4	%
Total Mcfe Production		6,542,167		4,022,472			2,519,695			62.6	%
Average Realized Price per Mcfe	$	5.96	$	7.92		$	(1.96	)		(24.8	%)

(a) Realized derivatives are included in Gain (Loss) on Derivatives, Net on our Consolidated Statements of Operations.

Average realized price received for oil and gas during the third quarter of 2012, after the effect of derivative activities, was $5.96 per Mcfe, a decrease of 24.8%, or $1.96 per Mcfe, from the same quarter in 2011. This decrease was primarily due to a higher percentage of sales of natural gas and natural gas liquids when compared to our sales mix during the third quarter of 2011 coupled with a decline in the market price for natural gas and natural gas liquids. The average price for oil and condensate, after the effect of derivative activities, increased 3.3%, or $2.88 per barrel, to $89.00 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 24.5%, or $1.24 per Mcf, to $3.82 per Mcf. The average price for our natural gas liquids, after the effect of derivative activities, decreased 22.2%, or $12.13 per barrel, to $42.55 per barrel. Our derivative activities effectively increased net realized prices by $0.65 per Mcfe in the third quarter of 2012 and $0.40 per Mcfe in the third quarter of 2011.

Production volumes in the third quarter of 2012 increased 62.6% from the third quarter of 2011. Natural gas production increased approximately 88.3% and our natural gas liquids production increased 61.4%, primarily due to the production in our Marcellus Shale drilling operations in Pennsylvania. In our Butler County, Pennsylvania operated area, during June 2012, our midstream provider put into service the Bluestone Plant which added to our existing production and processing capacity in the region.

Oil production increased in the third quarter of 2012 by 1.6% to 182,759 barrels as compared to the same period in 2011. The natural decline of our Illinois Basin properties was offset by increased oil production from our ASP pilot program and encouraging results of selective infill drilling and recompletion operations in the region.

Overall, our production for the three months ended September 30, 2012 averaged 71,111 Mcfe per day, of which 74.4% was attributable to natural gas, 16.7% to oil and 8.9% was a result of natural gas liquids production. Our production for the three months ended September 30, 2011 averaged 43,723 Mcfe per day, of which 64.2% was attributable to natural gas, 26.9% to oil and 8.9% was a result of natural gas liquids production.

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Statements of Operations for the three-month periods ended September 30, 2012 and 2011 are as follows:

	For Three Months Ended September 30,
	2012			2011			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	34,711		$	30,259			4,452			14.7	%
Field Services Revenue		4,170			442			3,728			N/M
Other Revenue		48			54			(6	)		(11.1	%)
TOTAL OPERATING REVENUE		38,929			30,755			8,174			26.6	%
OPERATING EXPENSES
Production and Lease Operating Expense		11,234			8,990			2,224			25.0	%
General and Administrative Expense		6,858			4,461			2,397			53.7	%
Loss on Disposal of Assets		16			6			10			166.7	%
Impairment Expense		292			2,379			(2,087	)		(87.7	%)
Exploration Expense		1,206			303			903			298.0	%
Depreciation, Depletion, Amortization and Accretion		12,396			7,762			4,634			59.7	%
Field Services Operating Expense		2,985			618			2,367			N/M
Other Operating Income		399			(23	)		422			N/M
TOTAL OPERATING EXPENSES		35,386			24,496			10,890			44.5	%
INCOME FROM OPERATIONS		3,543			6,259			(2,716	)		(43.4	%)
OTHER INCOME (EXPENSE)
Interest Expense		(852	)		(474	)		378			79.7	%
Gain (Loss) on Derivatives, Net		(5,893	)		12,174			18,067			148.4	%
Other Income (Expense)		(497	)		42			539			N/M
Gain (Loss) on Equity Method Investments		(174	)		105			279			265.7	%
TOTAL OTHER INCOME (EXPENSE)		(7,416	)		11,847			19,263			162.6	%
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(3,873	)		18,106			(21,979	)		(121.4	%)
Income Tax (Expense) Benefit		2,131			(5,440	)		7,571			139.2	%
INCOME (LOSS) FROM CONTINUING OPERATIONS		(1,742	)		12,666			(14,408	)		(113.8	%)
Loss From Discontinued Operations, Net of Income Taxes		(258	)		(20,812	)		20,554			98.8	%
NET LOSS		(2,000	)		(8,146	)		6,146			75.4	%
Net Income Attributable to Noncontrolling Interests		193			44			149			N/M
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(2,193	)		(8,190	)		5,997			73.2	%

Field services revenue for the three months ended September 30, 2012 and 2011 was approximately $4.2 million and $0.4 million, respectively. We generate field services revenue from various field service activities such as the management of water sourcing, water transfer and water disposal activities in the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, and particularly water transfer to service well completion activities.

Production and lease operating expenses increased approximately $2.2 million, or 25.0%, in the third quarter of 2012 from the same period in 2011. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin as they relate to variable type costs such as compression, processing and gathering. Additionally, the Commonwealth of Pennsylvania instituted the Pennsylvania Impact Fee during the first quarter of 2012, which accounted for approximately $0.7 million in expense for the period. On a per unit of production basis, our Production and Lease Operating Expenses decreased to $1.72 per Mcfe during the three months ended September 30, 2012 from $2.23 per Mcfe during the three months ended September 30, 2011.

G&A expenses for the third quarter of 2012 increased approximately $2.4 million, or 53.7%, to $6.9 million from the same period in 2011. The increase in our G&A Expenses during the three month period ended September 30, 2012 was affected by a number of factors including the growth of our Appalachian Basin operations and our corporate headquarters. On a per unit of production basis, our G&A Expenses decreased to $1.05 per Mcfe during the three months ended September 30, 2012 from $1.11 per Mcfe during the three months ended September 30, 2011.

Impairment expenses for the third quarter of 2012 and 2011 totaled approximately $0.3 million and $2.4 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expenses incurred during the three-month period ended September 30, 2012 are primarily related to expiring undeveloped acreage. For the three months ended September 30, 2011, approximately $0.8 million in expense is related to lease expirations. In addition, we incurred a charge of approximately $1.6 million due to the impairment of a refrigeration plant in our Butler County, Pennsylvania operation region which was in use before the commencement of operations of the cryogenic gas processing plants which process our gas. With the larger scale gas processing capabilities now available in the region there is no further value for the refrigeration plant.

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Exploration expensefor the three months ended September 30, 2012 was approximately $1.2 million as compared to $0.3 million for the three months ended September 30, 2011. The expenses incurred in the third quarter of 2012 were due to geological and geophysical type expenditures and delay rental payments primarily associated with leases in the Appalachian Basin, accounting for approximately $0.6 million each, as compared to the expense during the third quarter of 2011 which were primarily related to delay rental payments.

DD&A expenses for the three months ended September 30, 2012 increased approximately $4.6 million, or 59.7%, from $7.8 million for the same period in 2011. The period over period increase in DD&A Expenses is consistent with the growth in our asset base, reserves and production since the comparable period in 2011.

Field services operating expense for the three months ended September 30, 2012 and 2011 was approximately $3.0 million and $0.6 million, respectively. Our field services operating expenses are largely variable in nature and fluctuate commensurate with our level of activity. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, particularly those associated with water transfer for well completion operations.

Interest expense for the three months ended September 30, 2012 was approximately $0.9 million, as compared to $0.5 million during the third quarter of 2011. The increase in interest expense was due to our higher average long-term debt balance, including our Second Lien Credit Agreement, which carries a higher interest rate than our Senior Credit Facility.

Gain (loss) on derivatives, net was a loss of approximately $5.9 million for the third quarter of 2012, as compared to a gain of $12.2 million for the same period in 2011. Changes were attributable to the volatility of oil and gas commodity prices 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) for the three months ended September 30, 2012 was a loss of approximately $0.5 million. The loss incurred during the third quarter of 2012 was primarily due to a post-closing adjustment to the proceeds from the sale of our interest in Keystone Midstream during the second quarter of 2012.

Income tax(expense) benefit was a benefit of approximately $2.1 million for the three months ended September 30, 2012, as compared to expense of approximately $5.4 million for the three months ended September 30, 2011. The change was primarily due to increases in expense due to our derivative mark-to-market adjustments and DD&A expense during the third quarter of 2012.

Net loss attributable to Rex Energy for the third quarter of 2012 was a loss of approximately $2.2 million, as compared to $8.2 million for the comparable period in 2011, as a result of the factors discussed above.

35

Comparison of the Nine Months Ended September 30, 2012 to the Nine Months Ended September 30, 2011.

Oil and gas revenue for the nine-month periods ended September 30, 2012 and 2011 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:

	For Nine Months Ended September 30,
	2012			2011			Change			%
Oil and Gas Revenues:
Oil and condensate sales revenue	$	48,587		$	47,549		$	1,038			2.2	%
Oil derivatives realized (a)	$	(286	)	$	(648	)	$	362			55.9	%
Total oil and condensate revenue and derivatives realized	$	48,301		$	46,901		$	1,400			3.0	%
Gas sales revenue	$	35,917		$	26,218		$	9,699			37.0	%
Gas derivatives realized (a)	$	13,394		$	4,463		$	8,931			200.1	%
Total gas revenue and derivatives realized	$	49,311		$	30,681		$	18,630			60.7	%
Natural gas liquid revenue	$	9,389		$	7,320		$	2,069			28.3	%
Natural gas liquid derivatives realized (a)	$	248		$	—		$	248			100.0	%
Total natural gas liquid revenue and derivatives realized	$	9,637		$	7,320		$	2,317			31.7	%
Consolidated sales	$	93,893		$	81,087		$	12,806			15.8	%
Consolidated derivatives realized (a)	$	13,356		$	3,815		$	9,541			250.1	%
Total oil and gas revenue and derivatives realized	$	107,249		$	84,902		$	22,347			26.3	%
Total Mcfe Production		17,755,615			9,696,957			8,058,654			83.1	%
Average Realized Price per Mcfe	$	6.04		$	8.76		$	(2.72	)		(31.1	%)

(a) Realized derivatives are included in Gain (Loss) on Derivatives Net on our Consolidated Statements of Operations.

Average realized price received for oil, natural gas and natural gas liquids during the first nine months of 2012, after the effect of derivative activities, was $6.04 per Mcfe, a decrease of 31.1%, or $2.72 per Mcfe, from the same period in 2011. This decrease was primarily due to a higher percentage of sales from natural gas and natural gas liquids when compared to our sales mix during the first nine months of 2011 coupled with a decline in the market price for natural gas and natural gas liquids. The average price for oil and condensate, after the effect of derivative activities, increased 1.8%, or $1.60 per barrel, to $92.15 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 29.7%, or $1.58 per Mcf, to $3.74 per Mcf. The average price for natural gas liquids, after the effect of derivative activities, decreased 23.8%, or $12.74 per barrel, to $40.74 per barrel. Our derivative activities effectively increased net realized price by $0.75 per Mcfe in the first nine months of 2012 and $0.39 per Mcfe in the first nine months of 2011.

Production volumes in the first nine months of 2012 increased 82.4% to 64,802 Mcfe per day from the first nine months of 2011. Natural gas production increased approximately 128.7% and our natural gas liquids production increased by 72.8%, primarily due to the production in our Marcellus Shale drilling operations in Pennsylvania. In our Butler County, Pennsylvania operated area, during June 2012, our midstream provider put into service the Bluestone Plant which added to our existing production and processing capacity in the region.

Oil production increased during the first nine months of 2012 by 1.2% as compared to the same period in 2011. The natural decline of our Illinois Basin properties was offset by increased oil production from our ASP pilot program and encouraging results from selective infill drilling and recompletion operations in the region.

Overall, our production for the first nine months of 2012 averaged 64,802 Mcfe per day, of which 74.3% was attributable to natural gas, 17.7% to oil and 8.0% was a result of natural gas liquids production. Our production for the first nine months of 2011 averaged 35,520 Mcf per day, of which 59.5% was attributable to natural gas, 32.0% to oil and 8.5% was a result of natural gas liquids production.

36

Statements of Operations for the nine-month periods ended September 30, 2012 and 2011 are as follows:

	For Nine Months Ended September 30,
	2012			2011			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	93,893		$	81,087		$	12,806			15.8	%
Field Services Revenue		8,990			1,679			7,311			N/M
Other Revenue		137			158			(21	)		(13.3	%)
TOTAL OPERATING REVENUE		103,020			82,924			20,096			24.2	%
OPERATING EXPENSES
Production and Lease Operating Expense		34,505			24,055			10,450			43.4	%
General and Administrative Expense		18,043			18,603			(560	)		(3.0	%)
Loss on Disposal of Asset		110			464			(354	)		(76.3	%)
Impairment Expense		3,357			2,928			429			14.7	%
Exploration Expense		3,511			2,203			1,308			59.4	%
Depreciation, Depletion, Amortization and Accretion		33,082			19,641			13,441			68.4	%
Field Services Operating Expense		5,706			1,637			4,069			248.6	%
Other Operating Expense (Income)		693			(85	)		778			N/M
TOTAL OPERATING EXPENSES		99,007			69,446			29,561			42.6	%
INCOME FROM OPERATIONS		4,013			13,478			(9,465	)		(70.2	%)
OTHER INCOME (EXPENSE)
Interest Expense		(3,655	)		(1,024	)		2,631			256.9	%
Gain on Derivatives, Net		5,188			12,787			(7,599	)		(59.4	%)
Other Income		92,241			61			92,180			N/M
Loss on Equity Method Investments		(3,738	)		(165	)		(3,573	)		N/M
TOTAL OTHER INCOME		90,036			11,659			78,377			N/M
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		94,049			25,137			68,912			N/M
Income Tax Expense		(35,768	)		(8,207	)		27,561			N/M
INCOME FROM CONTINUING OPERATIONS		58,281			16,930			41,351			244.2	%
Loss From Discontinued Operations, Net of Income Taxes		(8,662	)		(29,195	)		20,533			70.3	%
NET INCOME (LOSS)		49,619			(12,265	)		61,884			N/M
Net Income (Loss) Attributable to Noncontrolling Interests		516			(14	)		530			N/M
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	49,103		$	(12,251	)		61,354			N/M

Field services revenue for the nine months ended September 30, 2012 and 2011 was approximately $9.0 million and $1.7 million, respectively. We generate field services revenue from various field service activities such as the management of water sourcing, water transfer and water disposal activities in the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, and particularly water transfer to service well completion activities.

Production and lease operating expenses increased approximately $10.5 million, or 43.4%, in the first nine months of 2012 from the same period in 2011. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin as they relate to variable type costs such as compression, processing and gathering. Additionally, the Commonwealth of Pennsylvania instituted the Pennsylvania Impact Fee during the first quarter of 2012, which accounted for approximately $4.6 million in expense for the period. On a per unit of production basis, Production and Lease Operating Expenses decreased from $2.48 for the nine months ending September 30, 2011 to $1.79 for the nine months ending September 30, 2012.

G&A expenses for the first nine months of 2012 decreased approximately $0.6 million, or 3.0%, to $18.0 million from the same period in 2011. We recorded approximately $2.5 million related to the settlement of our lawsuit in the Appalachian Basin during the second quarter of 2011, which was partially offset by a number of factors including the growth of our Appalachian Basin operations and our corporate headquarters. On a per unit of production basis, our G&A Expenses decreased to $1.02 per Mcfe during the nine months ended September 30, 2012 from $1.92 per Mcfe during the three months ended September 30, 2011.

Impairment expenses for the first nine months of 2012 and 2011 totaled approximately $3.4 million and $2.9 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first nine months of 2012 and 2011 is primarily related lease expirations and anticipated lease expirations on acreage where we are not planning any future development. In addition, we incurred a charge of approximately $1.6 million due to the impairment of a refrigeration plant during the first nine months of 2011 in our Butler County, Pennsylvania operation region which was in use before the commencement of operations of the cryogenic gas processing plants which process our gas. With the larger scale gas processing capabilities now available in the region there is no further value for the prior refrigeration plant.

37

Exploration expensefor the first nine months of 2012 was approximately $3.5 million, as compared to $2.2 million for the same period during 2011. Approximately $3.2 million of the expense incurred in 2012 was due to geological and geophysical expenditures and delay rental payments primarily associated with leases in the Appalachian Basin. The remaining $0.3 million spent during the first nine months of 2012 is related to the plugging of two exploratory Marcellus Shale wells that were spud during 2011 in Butler County, Pennsylvania. Minimal drilling was completed on these wells before a strategic decision was made to abandon the well locations and reallocate the remaining capital to other leases that will enable us to hold additional acreage by production. The expenses incurred in 2011 were due to geological and geophysical expenditures and delay rental payments primarily associated with leases in the Appalachian Basin.

DD&A expenses for the first nine months of 2012 increased to approximately $33.1 million, an increase of 68.4%, from $19.6 million for the same period in 2011. The period over period increase in DD&A Expenses is consistent with the growth in our asset base, reserves and production since the comparable period in 2011.

Field services operating expense for the nine months ended September 30, 2012 and 2011 was approximately $5.7 million and $1.6 million, respectively. Our field services operating expenses are largely variable in nature and fluctuate commensurate with our level of activity. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, particularly those associated with water transfer for well completion operations.

Interest expense for the first nine months of 2012 was approximately $3.7 million, as compared to $1.0 million during the first nine months of 2011. The increase in interest expense was due to our higher average long-term debt balance, including our Second Lien Credit Agreement, which carries a higher interest rate than our Senior Credit Facility.

Gain (loss) on derivatives, net was a gain of approximately $5.2 million for the first nine months of 2012 as compared to a gain of $12.8 million for the same period in 2011. Changes were attributable to the volatility of oil and gas commodity prices 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 for the nine months ended September 30, 2012 was a gain of approximately $92.2. The gain recognized during the second quarter of 2012 is attributable to the sale of our investment in Keystone Midstream, for which we received net proceeds of approximately $121.4 million, before a post-closing adjustment of $0.5 million.

Income tax expense was approximately $35.8 million for the nine months ended September 30, 2012 as compared to $8.2 million for the nine months ended September 30, 2011. The change was primarily due to the tax effect of the gain on the sale of our investment in Keystone Midstream during the second quarter of 2012.

Net income (loss) attributable to Rex Energy for the first nine months of 2012 was approximately $49.1 million, as compared to a loss of approximately $12.3 million for the comparable period in 2011 as a result of the factors discussed above.

38

Capital Resources and Liquidity

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the three and nine months ended September 30, 2012, we spent $62.7 million and $170.2 million, respectively, of capital on drilling projects, facilities and related equipment and acquisitions of unproved acreage. We funded our capital program with net cash flows from operations, borrowings under our Senior Credit Facility, net proceeds from our public offering of common stock and net proceeds that we received from the sale of our interest in Keystone Midstream. The remainder of our 2012 capital budget is expected to be funded primarily by cash flow from operations, non-core assets sales 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 drop in 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 securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Our ability to fund our capital expenditure program is dependent upon the level of commodity prices and the success of our exploration programs in replacing our existing oil and gas reserves. If commodity prices decrease, our operating cash flows may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of commodity prices on cash flows can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our acquisitions, development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under the Senior Credit Facility. Under extreme circumstances, commodity price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

Our cash flows from operations are driven by commodity prices and production volumes. Prices for oil and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations and borrowings from our Senior Credit Facility have been primarily used to fund exploration and development of our oil and gas interests. As of September 30, 2012, we had $168.0 million available for borrowing under our Senior Credit Facility with a current borrowing base of $290.0 million and $50.0 million available for borrowing under our Second Lien Credit Agreement of $100.0 million. We are not restricted as to our borrowings under the Senior Credit Facility; however we are subject to the minimum financial requirements detailed in Note 6,Long-Term Debt, to our Consolidated Financial Statements.

Future Liquidity Considerations

During October 2012, we entered into an ethane transportation agreement with Enterprise Liquids Pipeline LLC (“Enterprise”) to transport ethane produced in our Butler County, Pennsylvania operated area from certain delivery points to a natural gas storage complex at Mont Belvieu in the state of Texas where it will ultimately be marketed and sold. During the term of the agreement we are obligated to provide from 3,000 barrels of ethane per day, at a minimum, to 11,000 barrels of ethane per day, at a maximum, and pay a fee for any shortfalls of these volumes. The term of the agreement is expected to begin in July 2014 and ending in June 2029. In the event that we do not provide any ethane for transportation, we may be obligated to pay approximately $0 in 2012, $0 in 2013, $3.6 million in 2014, $10.7 million in 2015, $17.8 million in 2016 and $324.3 million thereafter. These amounts are determined based on current agreement transportation rates. In connection with the entry into the transportation agreement, we concurrently entered into a guaranty agreement whereby we have guaranteed the payment of obligations under the transportation agreement up to a maximum of $356.4 million.

Financial Condition and Cash Flows for the Nine Months Ended September 30, 2012 and 2011

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

	Nine Months Ended September 30, ($ in Thousands)
	2012			2011
Cash flows provided by operations	$	25,833		$	51,973
Cash flows used in investing activities		(51,331	)		(196,981	)
Cash flows provided by financing activities		17,485			143,601
Net decrease in cash and cash equivalents	$	(8,013	)	$	(1,407	)

Net cash provided by operating activities decreased by approximately $26.1 million in the first nine months of 2012 over the same period in 2011. The decrease in 2012 was affected by a combination of factors, including an increase Lease Operating Expense, interest and taxes. Our increase in production during the first nine months of 2012 as compared to the first nine months of 2011 had a minimal effect on operating cash flows as a result of a decrease in natural gas prices.

Net cash used in investing activities decreased by approximately $145.7 million from the first nine months of 2011 to $51.3 million in the first nine months of 2012. This change is largely attributable to the proceeds received on the sale of Keystone Midstream of approximately $121.4 million, before a post closing adjustment of approximately $0.5 million. Partially offsetting this influx of cash were increased expenditures on drilling and completion expenditures, particularly in our Marcellus and Utica Shale exploration areas, as compared to 2011. This increase was also impacted by a realization of restricted cash during the first nine months of 2011 of $16.1 million. The change in restricted cash during the first nine months of 2011 was due to an agreement with Sumitomo Corporation, whereby Sumitomo Corporation agreed to fund the cost of leasing acreage in Butler County, Pennsylvania. The balance of restricted cash decreased, thereby increasing our available cash, as leases were executed.

Net cash provided by financing activities decreased by approximately $126.1 million from the first nine months of 2011 to $17.5 million for the first nine months of 2012. The decrease in cash from financing activities is primarily due to net repayments of debt of $52.3 million during the first nine months of 2012 as compared to net borrowings of $144.0 million during the first nine months of 2011, which was partially offset by the proceeds of our public offering of common stock during the first quarter of 2012.

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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 three and nine months ended September 30, 2012, 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, 2011. 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, DD&A, unrealized losses from financial derivatives, the retroactive portion of the Pennsylvania Impact Fee, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

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

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

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

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

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, 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 consolidated 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. In addition, because we use capital assets, DD&A 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 income determined under GAAP and EBITDAX to evaluate our performance.

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For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX. The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented ($ in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net Income (Loss) From Continuing Operations	$	(1,742	)	$	12,666		$	58,281		$	16,930
Net (Income) Loss Attributable to Noncontrolling Interests		(193	)		(44	)		(516	)		14
Income (Loss) From Continuing Operations Attributable to Rex Energy		(1,935	)		12,622			57,765			16,944
Add Back Retroactive Portion of New Pennsylvania Impact Fee		—			—			2,809			—
Add Back Depletion, Depreciation, Amortization and Accretion		12,396			7,762			33,082			19,641
Add Back Non-Cash Compensation Expense		1,305			295			2,147			1,295
Add Back Interest Expense		852			474			3,655			1,024
Add Back Impairment Expense		292			2,379			3,357			2,928
Add Back Exploration Expenses		1,206			303			3,511			2,203
Add Back (Less) Loss (Gain) on Disposal of Assets		526			6			(92,128	)		464
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives		10,167			(10,572	)		8,167			(8,972	)
Less Non-Cash Portion of Noncontrolling Interests		(36	)		(8	)		(64	)		(139	)
Add Back (Less) Income Tax Expense (Benefit)		(2,131	)		5,440			35,768			8,207
Add Back Non-Cash Portion of Equity Method Investment		173			416			4,294			1,118
EBITDAX From Continuing Operations	$	22,815		$	19,117		$	62,363		$	44,713
Net Loss From Discontinued Operations	$	(258	)	$	(20,813	)	$	(8,662	)	$	(29,197	)
Add Back Depletion, Depreciation, Amortization and Accretion		—			(84	)		—			77
Add Back Non-Cash Compensation Expense		(43	)		19			(31	)		46
Add Back Impairment Expense		—			—			12,951			11,255
Add Back Exploration Expenses		329			30,249			810			31,562
Add Back Loss on Disposal of Assets		4			—			148			—
Less Income Tax Benefit		(203	)		(9,808	)		(6,064	)		(15,073	)
Add EBITDAX From Discontinued Operations	$	(171	)	$	(437	)	$	(848	)	$	(1,330	)
EBITDAX (Non-GAAP)	$	22,644		$	18,680		$	61,515		$	43,383

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 nine months ended September 30, 2012, the net realized gains on oil and natural gas derivatives were approximately $4.3 million and $13.4 million respectively, as compared to net realized gains of approximately $1.6 million and $3.8 million for the comparable period in 2011. These gains are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of September 30, 2012, we had approximately 85.9%, 77.3% and 27.5% of our current oil production on an annualized basis hedged through 2012, 3013 and 2014, respectively, and 68.2%, 82.4% and 20.5% of our current gas production on an annualized basis hedged through 2012, 2013 and 2014, respectively. In addition, we had approximately 34.2% of our current natural gas liquid production hedged on an annualized basis for 2012 and 2013.

For the three month and nine months ended September 30, 2012, the net unrealized gains or losses on commodity derivatives was a loss of $10.2 million and a loss of $8.2 million as compared to a gain of $10.6 million and a gain of $9.0 million for the comparable period in 2011. 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 four counterparties and have a netting agreement in place with our counterparties. While we do not obtain collateral to support the agreements, we do monitor the financial viability of our 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.

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For a summary of our current oil and natural gas derivative positions at September 30, 2012, refer to Note 7 of our Consolidated Financial Statements, Fair Value of Financial and Derivative Instruments.

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

Commodity Price Risk

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period 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 production through September 30, 2012, we project that a 10% decline in the price per barrel of oil and natural gas liquids and the price per Mcf of gas from the first nine months of the 2012 average would reduce our gross revenues, before the effects of derivatives, for the remaining three months of 2012 by approximately $3.1 million.

We have designed our hedging program to reduce the risk of price volatility for our production in the natural gas and 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 fixed rate swap contracts, collars, swaptions, and put options. 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 September 30, 2012, we had the following commodity derivative contracts outstanding:

Period	Volume	Put Option		Floor		Ceiling		Swap		Fair Market Value ($ in Thousands)
Oil
2012—Collar	150,000 Bbls	$	—	$	68.39	$	111.08	$	—	$	(73	)
2013—Collar	540,000 Bbls		—		72.44		112.56		—		(322	)
2014—Three Way Collar	192,000 Bbls		65.00		80.00		106.25		—		(391	)
	882,000 Bbls									$	(786	)
Natural Gas
2012—Swap	1,440,000 Mcf	$	—	$	—	$	—	$	4.06	$	552
2012—Swaption	150,000 Mcf		—		—		—		5.25		214
2012—Three Way Collar	660,000 Mcf		3.66		4.48		5.13		—		334
2012—Collar	750,000 Mcf		—		4.70		5.89		—		946
2013—Swap	5,970,000 Mcf		—		—		—		3.82		51
2013—Three Way Collar	2,520,000 Mcf		3.35		4.17		4.88		—		697
2013—Collar	3,360,000 Mcf		—		4.77		5.68		—		3,439
2013—Put	2,640,000 Mcf		—		5.00		—		—		2,754	a
2014—Call	1,800,000 Mcf		—		—		5.00		—		(491	)
2014—Three Way Collar	600,000 Mcf		2.75		3.50		4.25		—		(117	)
2014—Swap	1,200,000 Mcf		—		—		—		3.42		(612	)
2014—Collar	1,800,000 Mcf		—		3.51		4.43		—		(365	)
	22,890,000 Mcf									$	7,402
Natural Gas Liquids
2012—Swap	27,000 Bbls	$	—	$	—	$	—	$	43.26	$	112
2013—Swap	108,000 Bbls		—		—		—		43.26		446
	135,000 Bbls										558

^a  Includes liability of approximately $0.5 million for premium due upon settlement of contract.

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Interest Rate Risk

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 have used an interest rate swap agreement in the past to manage risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. We currently do not have any interest rate derivative contracts in place.

Item 4. Controls And Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), to allow timely decisions regarding required disclosure.

Our management (with the participation of our CEO and CFO) has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our CEO and CFO have concluded that, as of September 30, 2012, our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were 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.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

Our management, including our CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been, or will be, detected.

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PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

The information set forth under the subsectionsLegal ReservesandEnvironmental in Note 11,Commitments and Contingencies, to our Consolidated Financial Statements included in Item 1 of Part 1 of this report is incorporated herein by reference.

Item 1A. Risk Factors.

Other than as provided below, during the quarter ended September 30, 2012, 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, 2011.

Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

We describe our identified drilling locations and some of our plans to explore those drilling locations in our periodic reports filed with the Securities and Exchange Commission. Our identified drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil, NGLs or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil, NGLs or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing a well, resulting in a reduction in production from the well or abandonment of the well. If we drill wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the areas in which we operate may not be indicative of future or long-term production rates. Ultimately, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our identified drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has identified and scheduled drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. All of our drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, availability of drilling services and equipment, lease expirations, gathering system, marketing and pipeline transportation constraints, oil and natural gas prices, drilling and production costs, drilling results and other factors. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. The SEC rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Item 6. Exhibits.

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Form 10-Q and incorporated herein by reference.

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SIGNATURES

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

	REX ENERGY CORPORATION (Registrant)
Date: November 9, 2012	By:	/s/ Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)
Date: November 9, 2012	By:	/s/ Michael L. Hodges
		Chief Financial Officer (Principal Financial Officer)

INDEX TO 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 Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.2	Certificate of Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.3	Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on May 11, 2012).
4.1	Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
4.2	Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
10.1*	Tenth Amendment to Credit Agreement by and among Rex Energy Corporation, KeyBank National Association (“KeyBank”), as Administrative Agent, and the other lenders signatory thereto effective September 5, 2012.
10.2*	Second Amendment to Second Lien Credit Agreement by and among Rex Energy Corporation, KeyBank as Administrative Agent, and the other lenders signatory thereto effective September 5, 2012.
31.1*	Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2*	Certification of Interim 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.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

* These exhibits are filed herewith.

** These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.