Rex Energy 8K Index to Financial Statements | SEC 3 Sep 13

Exhibit 99.1

REX ENERGY CORPORATION

INDEX TO FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firms			2

Consolidated Balance Sheets at December 31, 2012 and 2011			4

Consolidated Statements of Operations for the Years ended December 31, 2012, 2011 and 2010			5

Consolidated Statements of Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) and for the Years ended December 31, 2012, 2011 and 2010			6

Consolidated Statements of Cash Flows for the Years ended December 31, 2012, 2011 and 2010			7

Notes to the Consolidated Financial Statements			8

Report of Independent Registered Public Accounting Firm

The Board of Directors

Rex Energy Corporation:

We have audited the accompanying consolidated balance sheets of Rex Energy Corporation and subsidiaries (the Company) as of December 31, 2012 and 2011 and the related consolidated statements of operations, changes in noncontrolling interests and stockholders’ equity (deficit), and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. The accompanying consolidated financial statements of the Company as of December 31, 2010, were audited by other auditors whose reports thereon dated March 3, 2011, expressed an unqualified opinion on those statements, before the effects of the adjustments to retrospectively adjust for disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

We also have audited adjustments to the 2010 consolidated financial statements to retrospectively adjust the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2010 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2010 consolidated financial statements taken as a whole.

We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company’s internal controls over financial reporting as of December 31, 2012, based on criteria established in Internal Controls—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 14, 2013 except for Notes 26 and 28

as to which the dates are September 3, 2013

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of

Rex Energy Corporation

State College, Pennsylvania

We have audited, before the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements, the accompanying consolidated statements of operations, owners’ equity and noncontrolling interests, and cash flows of Rex Energy Corporation for the year ended December 31, 2010. Rex Energy Corporation’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audit included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above, before the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements, present fairly, in all material respects, the consolidated results of operations and cash flows of Rex Energy Corporation for the year ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

We were not engaged to audit, review, or apply any procedures to the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements and, accordingly, we do not express an opinion or any other form of assurance about whether such retrospective adjustments are appropriate and have been properly applied. Those retrospective adjustments were audited by other auditors.

As discussed in Note 28 to the financial statements, the entity’s consolidated financial statements did not include disclosure of condensed consolidating financial information for Rex Energy Corporation, the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under SEC Regulation S-X. The requirement to include this disclosure arose subsequent to the issuance of the financial statements. The financial statements have been revised to include this disclosure.

/s/ Malin, Bergquist & Company, LLP

Malin, Bergquist & Company, LLP

Pittsburgh, Pennsylvania

March 3, 2011, except for Note 28, as it relates

to information for the year ended December 31, 2010,

for which the date is September 3, 2013

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

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


	December 31, 2012			December 31, 2011
ASSETS
Current Assets
Cash and Cash Equivalents	$	43,975		$	11,796
Accounts Receivable		24,980			17,717
Taxes Receivable		6,429			0
Short-Term Derivative Instruments		12,005			10,404
Assets Held For Sale		2,279			24,808
Inventory, Prepaid Expenses and Other		1,316			1,191

Total Current Assets		90,984			65,916
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		485,448			349,938
Unevaluated Oil and Gas Properties		161,618			123,241
Other Property and Equipment		50,073			43,542
Wells and Facilities in Progress		96,798			66,548
Pipelines		6,116			4,408

Total Property and Equipment		800,053			587,677
Less: Accumulated Depreciation, Depletion and Amortization		(146,038	)		(107,433	)

Net Property and Equipment		654,015			480,244
Deferred Financing Costs and Other Assets—Net		10,029			3,405
Equity Method Investments		16,978			41,683
Long-Term Deferred Tax Asset		0			1,727
Long-Term Derivative Instruments		704			8,576

Total Assets	$	772,710		$	601,551

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	31,134		$	41,558
Accrued Expenses		22,421			15,682
Short-Term Derivative Instruments		1,389			2,363
Current Deferred Tax Liability		539			2,141
Liabilities Related to Assets Held for Sale		52			1,622

Total Current Liabilities		55,535			63,366
8.875% Senior Notes Due 2020		250,000			0
Discount on Senior Notes		(1,742	)		0
Senior Secured Line of Credit and Long-Term Debt		991			225,138
Long-Term Derivative Instruments		1,510			1,275
Long-Term Deferred Tax Liability		23,625			84
Other Deposits and Liabilities		5,675			744
Future Abandonment Cost		24,822			18,670

Total Liabilities		360,416			309,277
Commitments and Contingencies (See Note 9)
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 53,213,264 shares issued and outstanding on December 31, 2012 and 44,859,220 shares issued and outstanding on December 31, 2011		52			44
Additional Paid-In Capital		451,062			376,843
Accumulated Deficit		(39,595	)		(84,888	)

Rex Energy Stockholders’ Equity		411,519			291,999
Noncontrolling Interests		775			275

Total Stockholders’ Equity		412,294			292,274

Total Liabilities and Stockholders’ Equity	$	772,710		$	601,551

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

($ and Shares in Thousands, Except Share and Per Share Data)


	Year Ended December 31,
	2012			2011			2010
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	134,574		$	111,879		$	67,224
Field Services Revenue		13,403			2,518			1,366
Other Revenue		162			209			173

TOTAL OPERATING REVENUE		148,139			114,606			68,763
OPERATING EXPENSES
Production and Lease Operating Expense		47,638			33,116			24,656
General and Administrative Expense		23,345			23,636			17,141
(Gain) Loss on Disposal of Asset		58			502			(16,395	)
Impairment Expense		20,585			14,631			8,863
Exploration Expense		4,782			2,507			2,578
Depreciation, Depletion, Amortization and Accretion		45,437			27,856			21,568
Field Services Operating Expense		8,240			1,750			1,188
Other Operating Expense		1,136			819			153

TOTAL OPERATING EXPENSES		151,221			104,817			59,752
INCOME (LOSS) FROM OPERATIONS		(3,082	)		9,789			9,011
OTHER INCOME (EXPENSE)
Interest Expense		(6,443	)		(2,514	)		(1,240	)
Gain on Derivatives, Net		10,687			18,916			6,055
Other Income (Expense)		98,549			79			(321	)
Income (Loss) from Equity Method Investments		(3,921	)		81			(200	)

TOTAL OTHER INCOME		98,872			16,562			4,294
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		95,790			26,351			13,305
Income Tax Expense		(38,549	)		(8,270	)		(5,500	)

INCOME FROM CONTINUING OPERATIONS		57,241			18,081			7,805
Loss From Discontinued Operations, Net of Income Taxes		(10,943	)		(33,457	)		(2,022	)

NET INCOME (LOSS)		46,298			(15,376	)		5,783
Net Income (Loss) Attributable to Noncontrolling Interests		819			(7	)		(253	)

NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	45,479		$	(15,369	)	$	6,036

Earnings Per Common Share:
Basic—income from continuing operations attributable to Rex common shareholders	$	1.09		$	0.41		$	0.18
Basic—loss from discontinued operations attributable to Rex common shareholders		(0.21	)		(0.76	)		(0.05	)

Basic—net income (loss) attributable to Rex common shareholders	$	0.88		$	(0.35	)	$	0.13

Basic—weighted average shares of common stock outstanding		51,543			43,930			43,281
Diluted—income from continuing operations attributable to Rex common shareholders	$	1.08		$	0.41		$	0.18
Diluted—loss from discontinued operations attributable to Rex common shareholders		(0.21	)		(0.76	)		(0.05	)

Diluted—net income (loss) attributable to Rex common shareholders	$	0.87		$	(0.35	)	$	0.13

Diluted—weighted average shares of common stock outstanding		52,025			44,476			43,670

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

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

(in Thousands)


	Common Stock				Additional Paid-In Capital		Accumulated Deficit			Rex Energy Stockholders’ Equity			Noncontrolling Interests			Total Stockholders’ Equity
	Shares		Par		Additional Paid-In Capital		Accumulated Deficit			Rex Energy Stockholders’ Equity			Noncontrolling Interests			Total Stockholders’ Equity
Balance December 31, 2009		36,818	$	37	$	292,372	$	(75,555	)	$	216,854		$	3,343		$	220,197
Non-cash compensation expense		0		0		965		0			965			0			965
Issuance of common stock, net of issuance costs		6,900		7		80,192		0			80,199			0			80,199
Capital contributions		0		0		0		0			0			287			287
Restricted stock, net		567		0		0		0			0			0			0
Stock option exercises		22		0		327		0			327			0			327
Deconsolidation of Keystone Midstream Services, LLC		0		0		0		0			0			(3,082	)		(3,082	)
Net Income (Loss)		0		0		0		6,036			6,036			(253	)		5,783

Balance December 31, 2010		44,307		44		373,856		(69,519	)		304,381			295			304,676
Non-cash compensation		0		0		1,625		0			1,625			0			1,625
Capital distributions		0		0		0		0			0			(13	)		(13	)
Restricted stock, net		413		0		0		0			0			0			0
Stock option exercises		139		0		1,362		0			1,362			0			1,362
Net Loss		0		0		0		(15,369	)		(15,369	)		(7	)		(15,376	)

Balance December 31, 2011		44,859		44		376,843		(84,888	)		291,999			275			292,274
Non-cash compensation		0		0		3,079		(186	)		2,893			0			2,893
Issuance of common stock, net of issuance costs		8,050		8		70,575		0			70,583			0			70,583
Restricted stock, net		252		0		0		0			0			0			0
Stock option exercises		52		0		565		0			565			0			565
Capital distributions		0		0		0		0			0			(319	)		(319	)
Net Income		0		0		0		45,479			45,479			819			46,298

Balance December 31, 2012		53,213	$	52	$	451,062	$	(39,595	)	$	411,519		$	775		$	412,294

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in Thousands)


	For the Years Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	46,298		$	(15,376	)	$	5,783
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
(Gain) Loss from Equity Method Investments		3,921			(81	)		200
Non-cash Expenses		3,191			1,745			1,251
Depreciation, Depletion, Amortization and Accretion		46,441			28,446			21,806
Deferred Income Tax Expense (Benefit)		23,665			(7,339	)		3,771
Unrealized (Gain) Loss on Derivatives		5,532			(12,704	)		(5,960	)
Dry Hole Expense		656			32,769			3
(Gain) Loss on Sale of Assets and Equity Method Investments		(100,551	)		502			(16,395	)
Impairment Expense		40,355			27,808			8,863
Changes in operating assets and liabilities
Accounts Receivable		(13,698	)		11,118			(14,527	)
Inventory, Prepaid Expenses and Other Assets		(92	)		86			(216	)
Accounts Payable and Accrued Expenses		(6,770	)		(1,128	)		32,323
Other Assets and Liabilities		(3,243	)		(1,339	)		(2,800	)

NET CASH PROVIDED BY OPERATING ACTIVITIES		45,705			64,507			34,102
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Leasing Initiatives		260			3,209			6,352
Change in Restricted Cash		0			16,086			(16,086	)
Contributions to Equity Method Investments		(4,087	)		(23,204	)		(14,018	)
Proceeds from the Sale of Assets and Equity Method Investments		133,425			2,729			79,229
Acquisitions of Undeveloped Acreage		(51,802	)		(78,569	)		(72,385	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(178,538	)		(196,825	)		(78,013	)

NET CASH USED IN INVESTING ACTIVITIES		(100,742	)		(276,574	)		(94,921	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		126,730			240,000			85,000
Repayments of Long-Term Debt and Lines of Credit		(351,000	)		(25,000	)		(98,000	)
Repayments of Loans and Other Notes Payable		(962	)		(879	)		(753	)
Proceeds from 8.875% Senior Notes, net of Discount		248,250			0			0
Debt Issuance Costs		(6,397	)		(2,615	)		(701	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		(234	)		0			0
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		70,583			0			80,192
Proceeds from the Exercise of Stock Options		565			1,362			220
Capital Distributions by the Partners of Consolidated Joint Ventures		(319	)		(20	)		0
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures		0			7			287

NET CASH PROVIDED BY FINANCING ACTIVITIES		87,216			212,855			66,245
NET INCREASE IN CASH		32,179			788			5,426
CASH—BEGINNING		11,796			11,008			5,582

CASH—ENDING	$	43,975		$	11,796		$	11,008

SUPPLEMENTAL DISCLOSURES
Interest Paid		7,568			1,549			846
Taxes Paid		12,824			312			299
NON-CASH ACTIVITIES
Equipment Financing		2,368			474			1,336

See accompanying notes to the consolidated financial statements

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

We are an independent oil and gas company operating in the Appalachian Basin and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian Shale drilling and exploration activities. In the Illinois Basin, we are focused on the implementation of enhanced oil recovery on our properties as well as conventional oil production. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. In addition to our drilling and exploration activities, we are also engaged in oil and gas field services, where we provide water sourcing, water disposal and water transfer capabilities for completion operations.

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.

Certain prior year amounts have been reclassified to conform to the report classifications for the year ended December 31, 2012, with no effect on previously reported net income, net income per share, accumulated deficit or stockholders’ equity. All prior year amounts that have been reclassified are immaterial.

We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31, 2012 and 2011 and the Consolidated Statements of Operations, Cash Flows and Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) for the years ended December 31, 2012, 2011 and 2010. Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. All intercompany transactions and accounts have been eliminated.

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 and Colorado. 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 5, 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. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.

Cash and Cash Equivalents

We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Accounts Receivable

Our trade accounts receivable, which are primarily from oil, natural gas and natural gas liquids (“NGL” or “NGLs”) sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and recorded an allowance for bad debts as necessary.

To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets.

At December 31, 2012, we carried approximately $18.1 million in production receivable, of which approximately $16.3 million were production receivables due from four purchasers. At December 31, 2011, we carried approximately $13.6 million in production receivables of which approximately $12.9 million were production receivables due from three purchasers. In addition, we carried approximately $2.1 million in receivables from Sumitomo Corporation at December 31, 2012 and $3.0 million at December 31, 2011 (see Note 4, Business and Oil and Gas Property Acquisition Dispositions, to our Consolidated Financial Statements) that was in relation to our joint operations.

Inventory

Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.

Oil and Natural Gas Property, Depreciation and Depletion

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

Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.

When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and oil prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success and future development plans. When evaluating the value of our unproved oil and gas properties, we utilize active market prices for similar acreage to use as a comparison tool against the carrying value of our properties. If the active market prices for similar acreage do not support our carrying values we then utilize estimates of future value that will be created from the future development of these properties. If future estimated fair value of these properties is lower than the capitalized cost, the capitalized cost is reduced to the estimated future fair value. We recognized approximately $20.6 million, $14.6 million and $8.9 million of impairment from continuing operations on certain oil and gas properties for the years ending December 31, 2012, 2011 and 2010, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 18, Impairment Expense, to our Consolidated Financial Statements.

Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.

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

Natural Gas and Oil Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil, natural gas and NGLs that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2012 and 2011, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, natural gas and NGL reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.

Deferred Financing Costs and Other Assets—Net

At December 31, 2012, we had deferred financing costs and other assets consisting of $10.0 million, which is primarily made up of loan costs that are amortized using the effective interest method and the straight line method over their respective estimated lives, which is, on average, three to eight years. We amortize any costs incurred to renew or extend the terms of existing debt over the contract term or estimated useful life, as applicable. For the years ended December 31, 2012, 2011 and 2010, we recorded amortization expense from continuing operations of $1.2 million, $0.8 million and $0.5 million, respectively.

The following is a summary of our deferred financing costs and other assets at the dates indicated:


	December 31, 2012 (in thousands)			December 31, 2011 (in thousands)
Deferred Financing Costs and Other Assets—Gross	$	9,524		$	5,637
Accumulated Amortization		(1,922	)		(2,329	)

Deferred Financing Costs and Other Assets—Net¹	$	7,602		$	3,308

¹	Does not include approximately $2.4 million associated with advanced royalty payments for the year ended December 31, 2012, for which we expect to recover through future production and royalties.

Specific to our loan costs, we have incurred gross debt issuance costs of approximately $6.1 million, $2.6 million and $0.7 million for the years ended December 31, 2012, 2011 and 2010, respectively, which are presented net of accumulated amortization of $1.9 million, $1.1 million and $0.6 million, respectively, and include deferred financing from our senior notes.

Future Abandonment Cost

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

Accretion expense from continuing operations during the years ended December 31, 2012, 2011 and 2010 totaled approximately $2.1 million, $1.5 million and $1.7 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. During 2012, we recognized an increase of $4.0 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 revised estimates were primarily the result of increased abandonment estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.


	December 31, 2012 ($ in Thousands)			December 31, 2011 ($ in Thousands)
Beginning Balance	$	18,670		$	17,222
Asset Retirement Obligation Incurred		598			235
Asset Retirement Obligation Settled		(428	)		(266	)
Asset Retirement Obligation Cancelled or Sold Well Properties		0			0
Asset Retirement Obligation Revision of Estimated Obligation		3,953			0
Asset Retirement Obligation Accretion Expense		2,029			1,479

Total Asset Retirement Obligation	$	24,822		$	18,670

Revenue Recognition

As it pertains to our exploration and production business segment, oil, NGL and natural gas revenue is recognized when the oil or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil or gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser.

For our field services segment, our services are generally sold based upon purchase orders, contracts or other agreements with customers that include fixed or determinable prices. We recognize revenue when services are performed and collection of the relevant receivables is probable. We contract for services either on a day rate or other contracted rate. In certain situations, revenue is generated from transactions that may include multiple products and services under one contract or agreement and which may be delivered to the customer over an extended period of time. Revenue from these arrangements is recognized in accordance with the above criteria and as each item or service is delivered.

Derivative Instruments

We use put and call options (collars), fixed rate swap contracts, swaptions, puts and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also, in the past, used interest rate swap agreements to manage interest rate risks associated with our variable rate credit facility. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2012, 2011 and 2010 we did not have any derivative instruments designated for hedge accounting.

For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 12, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

Income Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to other temporary differences.

Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted tax rate. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.

This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes

in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.

The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets.

We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 13, Income Taxes, to our Consolidated Financial Statements). Our policy is to recognize interest and penalties on any unrecognized tax benefits in interest expense and general and administrative expense, respectively.

Stock-based Compensation

We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant.

The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow when realized. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 17, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). Stock appreciation rights are classified as a liability and are re-measured at fair value each reporting period.

Capitalization of Interest

We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2012, 2011 and 2010, we capitalized interest costs of $3.0 million, $1.2 million and $0, respectively.

Earnings per Share

Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding during the period, including any potentially dilutive outstanding securities, such as options and warrants. The potentially dilutive outstanding securities are calculated using the treasury stock method. At December 31, 2012, we had 53,213,264 common shares outstanding, 502,253 options outstanding and 20,500

stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. For additional information, see Note 14, Earnings per Common Share, to our Consolidated Financial Statements.

Capital Leases

As a lessee, we determine if a lease is a capital lease if it meets one of four of the following criteria:

•

The ownership of the leased property transfers to us by the end of the lease term, or shortly thereafter, in exchange for the payment of a nominal fee.

•

The lease contains a bargain purchase option.

•

The lease term is equal to 75% or more of the estimated economic life of the leased property.

•

The present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executor costs such as insurance, maintenance, and taxes to be paid by the lessor, including any profit thereon, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at the lease inception over any related investment tax credit retained by the lessor and expected to be realized by the lessor.

As of December 31, 2012 we had capital leases on field vehicles being used in our Illinois and Appalachian Basin operations as well as in our field services operating segment. We recorded these leases as Other Property and Equipment on our Consolidated Balance Sheets in the amount of $1.6 million as of December 31, 2012, and $2.3 million as of December 31, 2011. The remaining obligation to be paid on these leases totaled approximately $1.5 million, of which $1.0 million was classified as Senior Secured Line of Credit and Long-Term Debt under Long-Term Liabilities and $0.5 million was classified as Accounts Payable under Current Liabilities on our Consolidated Balance Sheets, all of which is expected to be paid by 2016.

Recent 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 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 GAAP and International Financial Reporting Standards (“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.

In December 2010, the FASB issued ASU 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”). The amendments to the codification clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Additionally, the supplemental pro forma disclosures under Topic 805 have been expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments in ASU 2010-29 are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Although we have not entered into any significant business combinations in our recent history, we believe that ASU 2010-29 may have a material impact on future disclosures depending on the size and nature of any future business combinations that we may enter into. We adopted ASU 2010-29 on January 1, 2011.

3. BUSINESS SEGMENT INFORMATION

In 2012, we changed the structure of our internal organization causing a change in the composition of our segments. Accordingly, we have restated the items of segment information for earlier periods to reflect the change in our internal organization, as described in our Current Report on Form 8-K, filed on November 12, 2012.

We have two principal reportable segments, which are segregated based on the products and services that each provide: (a) exploration and production, and (b) field services. Our exploration and production segment engages in the exploration, acquisition, development and production of oil, natural gas and NGLs. Our field services segment operates and manages water sourcing, water transfer and water disposal services, primarily in the Appalachian Basin.

We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. All intercompany transactions, including those between consolidated business segments, are eliminated in consolidation. Summarized financial information concerning our segments is shown in the following table for 2012, 2011 and 2010 (in thousands):


	Exploration and Production			Field Services			Intercompany Eliminations			Consolidated Total
For the Year Ended December 31, 2012
Revenues	$	134,736		$	15,637		$	(2,234	)	$	148,139
Inter-Segment Revenues		0			(2,234	)		2,234			0

Total Revenues		134,736			13,403			0			148,139
Depreciation, Depletion and Amortization		44,955			482			0			45,437
Impairment Expense		20,505			80			0			20,585
Other Operating Expense(a)		76,063			10,859			(1,723	)		85,199
Interest Expense(b)		6,424			26			0			6,450
Other (Income) Expense(c)		(105,426	)		0			104			(105,322	)

Income (Loss) From Continuing Operations, Before Income Taxes	$	92,215		$	1,956		$	1,619		$	95,790

Total Assets	$	766,599		$	12,166		$	(6,055	)	$	772,710
Expenditures for Long-Lived Assets	$	227,913		$	3,134		$	(707	)	$	230,340
Equity Method Investments	$	16,978		$	0		$	0		$	16,978
For the Year Ended December 31, 2011
Revenues	$	112,088		$	3,546		$	(1,028	)	$	114,606
Inter-Segment Revenues		0			(1,028	)		1,028			0

Total Revenues		112,088			2,518			0			114,606
Depreciation, Depletion and Amortization		27,670			186			0			27,856
Impairment Expense		14,316			315			0			14,631
Other Operating Expense(a)		59,917			3,169			(756	)		62,330
Interest Expense(b)		2,523			1			0			2,524
Other (Income) Expense(c)		(19,021	)		(100	)		35			(19,086	)

Income (Loss) From Continuing Operations, Before Income Taxes	$	26,683		$	(1,053	)	$	721		$	26,351

Total Assets	$	600,049		$	7,143		$	(5,641	)	$	601,551
Expenditures for Long-Lived Assets	$	269,823		$	5,571		$	0		$	275,394
Equity Method Investments	$	41,683		$	0		$	0		$	41,683
For the Year Ended December 31, 2010
Revenues	$	67,397		$	1,718		$	(352	)	$	68,763
Inter-Segment Revenues		0			(352	)		352			0

Total Revenues		67,397			1,366			0			68,763
Depreciation, Depletion and Amortization		21,422			146			0			21,568
Impairment Expense		8,424			439			0			8,863
Other Operating Expense(a)		27,820			1,538			(37	)		29,321
Interest Expense(b)		1,308			0			0			1,308
Other (Income) Expense(c)		(5,602	)		0			0			(5,602	)

Income (Loss) From Continuing Operations, Before Income Taxes	$	14,025		$	(757	)	$	37		$	13,305

Total Assets	$	405,066		$	2,019		$	0		$	407,085
Expenditures for Long-Lived Assets	$	149,075		$	1,323		$	0		$	150,398
Equity Method Investments	$	18,399		$	0		$	0		$	18,399

(a)	Includes the following expenses: production and lease operating expenses, general and administrative expenses, (gain) loss on disposal of assets, exploration expenses, field services operating expenses and other operating expense.

(b)	Totals will not agree to Consolidated Statements of Operations due to exclusion of immaterial amounts of interest income, which is included in Other (Income) Expense.

(c)	Includes the following expenses: interest income, gain (loss) on derivative, net, other income (expense) and gain (loss) on equity method investments.

4. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS

Acquisitions

We have made no significant acquisitions for the years ended December 31, 2012, 2011 and 2010.

Dispositions

Keystone Midstream Services, LLC

On May 29, 2012, we closed the sale of our ownership in Keystone Midstream Services, LLC (“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 we recorded as Gain (Loss) on Equity Method Investments on our Consolidated Statement of Operations. During the third quarter of 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 held in escrow to be paid out over the course of the 12 months following closing. During the fourth quarter of 2012 we received approximately $7.2 million of the outstanding escrow amount. Any remaining escrow amounts received will be recognized in income when 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 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 of Keystone Midstream, including the post-closing adjustment of $0.5 million and the receipt of the escrow funds of $7.2 million, of $99.4 million, all of which was recorded as Other Income (Expense) in our Consolidated Statement of Operations. See Note 7,Equity Method Investments, to our Consolidated Financial Statements for additional information on Keystone Midstream.

Sumitomo Joint Venture

On September 30, 2010, we entered into a joint venture transaction with an affiliate of Sumitomo Corporation (“Sumitomo”). In Butler County, Pennsylvania we sold a 15% non-operated interest in approximately 40,700 net acres for approximately $30.6 million in cash at closing and $30.6 million in the form of a drilling carry of 80% of our drilling and completion costs in the area. Pursuant to the Participation and Exploration Agreement (the “Sumitomo PEA”), Sumitomo agreed to pay all of the costs to lease approximately 9,000 net acres in the Butler County Area of Mutual Interest (“AMI”) (the “Phase I Leasing”), and to pay to us a leasing management fee of $1,000 per net acre during the Phase I Leasing. The Phase I Leasing and drilling carry for Butler County were completed during the first quarter of 2011, resulting in final ownership percentages of 70% to us and 30% to Sumitomo. The cost of future leasing activities will be shared on a 70/30 basis, with Sumitomo paying to us a management fee of $150 per net acre acquired. In addition to the sale of undeveloped acreage, we also sold to Sumitomo 30% of our interests in 20 Marcellus Shale wells within the Butler County area and 30% of our interest in Keystone Midstream (for additional information on Keystone Midstream, seeNote 7, Equity Method Investments, to our Consolidated Financial Statements).

In our Marcellus Shale joint venture project areas with WPX Energy San Juan, LLC (formerly known as Williams Production Company, LLC) and Williams Production Appalachia, LLC (collectively, “Williams”), which was entered into in 2009, we sold to Sumitomo 20% of our interests in 23,500 net acres for approximately $19.0 million in cash at closing and $19.0 million in the form of a drilling carry of 80% of our drilling and completion costs in the areas. In addition, we sold 20% of our interests in 19 Marcellus Shale wells located in the Williams joint venture areas and 20% of our interest in RW Gathering, LLC (“RW Gathering”) (for additional information on RW Gathering, see Note 7, Equity Method Investments, to our Consolidated Financial Statements).

In addition to the areas above, we sold to Sumitomo 50% of our interests in approximately 4,500 net acres in Fayette and Centre Counties, Pennsylvania for $9.2 million in cash at closing and $9.2 million in the form of a drilling carry of 80% of our drilling and completion costs. Pursuant to the Sumitomo PEA, the drilling carry for these areas was to be applied, at our discretion, to drilling and completion costs attributable to either the Butler County or Williams joint venture areas. We elected to apply these drilling carries to other costs as permitted under the PEA, and consequently, as of December 31, 2011, there were no remaining drilling carries with Sumitomo.

At closing, we received approximately $99.5 million in cash, which included a reimbursement for leasing expenses incurred subsequent to the effective date of September 1, 2010, in the amount of approximately $7.6 million. Additionally, the cash payment included a reimbursement for drilling related expenses incurred subsequent to the effective date in the amount of approximately $7.5 million, which was applied against the drilling carry. Pursuant to industry rules, we do not make any accounting for the carried amounts paid on our behalf by Sumitomo. We recognized a gain of approximately $16.5 million on the Sumitomo transaction which is classified as (Gain) Loss on Disposal of Asset on our Consolidated Statement of Operations.

5. 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 and Colorado. During 2012, we sold various parcels of acreage throughout our DJ Basin holdings at varying prices, much of which was lower than the existing carrying value of similar remaining acreage at the time of sale. Market conditions in the region for similar assets have experienced a deterioration of price over the course of the last 12 months to which we have responded by modifying our marketing efforts. The assets remaining are available for immediate sale pending normal due diligence incurred during the course of normal business, with a sale expected within one year. The recording of Depreciation, Depletion, Amortization and Accretion (“DD&A”) expense related to our DJ Basin assets ceased in December 2011. During 2012, we continually evaluated the value, less cost to sell, of our DJ Basin assets and determined that the fair value of our assets was less than the carrying amount of the assets based on recent purchase and sale activities in the Basin. In total, we incurred approximately $19.8 million in Impairment Expense related to the write down of our DJ Basin assets during 2012. For additional information on impairment, see Note 18,Impairment Expense, to our Consolidated Financial Statements.

These assets were classified as Assets Held for Sale on our Balance Sheet as of December 31, 2012 and December 31, 2011, and the results of operations are reflected in Discontinued Operations in our Consolidated Statements of Operations. We included $2.3 million and $24.8 million of net assets located in the DJ Basin as Assets Held for Sale on our Consolidated Balance Sheets as of December 31, 2012 and 2011, respectively. We included approximately $0.1 million and $1.6 million of liabilities as Liabilities Related to Assets Held for Sale on our Consolidated Balance Sheets as of December 31, 2012 and 2011, respectively. These liabilities primarily relate to Accounts Payable and Accrued Expenses. Upon the completion of a sale, we will have no continuing activities in the DJ Basin or continuing cash flows from this region. For additional information on our remaining DJ Basin assets, see Note 26,Subsequent Events, to our Consolidated Financial Statements.

Summarized financial information for Discontinued Operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.


	December 31,
($ in thousands)	2012			2011			2010
Revenues:
Oil and Gas Sales	$	97		$	556		$	0

Total Operating Revenue		97			556			0
Costs and Expenses:
Production and Lease Operating Expense		353			493			0
General and Administrative Expense		660			1,745			782
Exploration Expense		867			33,812			2,664
Impairment Expense		19,770			13,177			0
Depreciation, Depletion, Amortization and Accretion		0			85			1
Other Operating Expense		8			1			0
Gain on Disposal of Asset		(2,126	)		0			0
Interest Expense		0			1			0
Other (Income) Expense		(3	)		1			0

Total Costs and Expenses		19,529			49,315			3,447
Income (Loss) from Discontinued Operations Before Income Taxes		(19,432	)		(48,759	)		(3,447	)
Income Tax (Expense) Benefit		8,489			15,302			1,425

Income (Loss) from Discontinued Operations, Net of Income Taxes	$	(10,943	)	$	(33,457	)	$	(2,022	)

Production
Crude Oil (Bbls)		1,272			6,939			0

6. CONSOLIDATED SUBSIDIARIES

Our consolidated subsidiaries make up 100.0% of our field services segment. For additional information, see Note 3,Business Segment Information, to our Consolidated Financial Statements.

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. Upon the return of our initial investments in Water Solutions, plus interest, our ownership percentage will change to 60% and the remaining 40% will be held by Sand Hills.

We fully consolidate the accounts of Water Solutions in our financial statements and account for the 20% equity interest owned by Sand Hills as a noncontrolling interest. Water Solutions is financed through cash contributions from its members and a credit facility upon which $0.7 million was drawn as of December 31, 2012. Water Solutions’ credit facility did not exist at December 31, 2011. There were no cash contributions during the 12 months ending December 31, 2012, and cash contributions during the 12 months ending December 31, 2011 were negligible. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of December 31, 2012 and 2011, with no restrictions or obligations to use certain assets to settle associated liabilities:


	December 31,
($ in thousands)	2012			2011
Assets
Cash and Cash Equivalents	$	741		$	374
Accounts Receivable		3,360			877
Inventory, Prepaid Expenses and Other		13			11
Other Property and Equipment		3,560			561
Wells and Facilities in Progress		221			134
Accumulated Depreciation, Depletion and Amortization		(501	)		(75	)
Deferred Financing Costs and Other Assets—Net		199			192

Total Assets	$	7,593		$	2,074

Liabilities
Accounts Payable	$	1,554		$	481
Accrued Expenses		1,036			119
Senior Secured Line of Credit and Long-Term Debt		965			100

Total Liabilities	$	3,555		$	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 December 31, 2012, R.E. Gas owned a 51% membership interest in NorthStar #3 and serves as the operator of the entity; the remaining 49% membership interest was owned by NorthStar. To supplement the operations of NorthStar #3, the entity entered into a promissory note with us. As of December 31, 2012 and 2011, the amount owed to us under the promissory note was $4.6 million and $4.9 million, respectively (for additional information see Note 10, Related Party Transactions, to our Consolidated Financial Statements).

A variable interest entity (“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 the financial results. 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 ample 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.

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


	December 31,
($ in thousands)	2012		2011
Assets
Cash and Cash Equivalents	$	14	$	10
Wells and Facilities in Progress		4,559		5,059

Total Assets	$	4,573	$	5,069
Liabilities
Accounts Payable	$	6	$	134
Note Payable		4,633		4,935

Total Liabilities	$	4,639	$	5,069

7. EQUITY METHOD INVESTMENTS

RW Gathering

RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly own with WPX Energy Inc. (“WPX”) and Sumitomo, with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania.

We recorded our investment in RW Gathering of approximately $17.0 million and $15.7 million as of December 31, 2012 and 2011, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During 2012, we contributed approximately $2.0 million in cash to RW Gathering to support current pipeline and gathering line construction, compared to $9.7 million during the same period in 2011. RW Gathering recorded net losses from continuing operations of $1.7 million, $0.4 million and $0.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and DD&A expense. Our share of the net loss from continuing operations is recorded on the Statements of Operations as Loss on Equity Method Investments.

When evaluating our Equity Method Investments for impairment we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. In the case of RW Gathering, the nature of its assets is such that under normal circumstances an entity would capitalize and evaluate the assets as a part of its producing well properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing well assets that utilize these gathering systems. As of December 31, 2012, we determined that we had the ability to recover the carrying amount of our investment in RW Gathering.

Keystone Midstream

On May 29, 2012, we closed the sale of our ownership in Keystone Midstream, which we had accounted for as an equity method investment. For additional information on the sale of Keystone Midstream, see Note 4,Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements.

Prior to 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 of approximately $28.1 million as of the date of sale and $26.0 million as of December 31, 2011, on our Consolidated Balance Sheets as Equity Method Investments. In 2012 and 2011, we contributed approximately $2.1 million and $13.5 million, respectively, to Keystone Midstream primarily to support the construction of cryogenic gas processing plants. Keystone Midstream recorded a net loss from continuing operations of $12.0 million as of May 29, 2012, net income of $1.6 million as of December 31, 2011 and a net loss of $0.5 million for the four-month period ended December 31, 2010. Included in the net loss recorded in 2012 were approximately $12.0 million of transaction expenses related to the sale of the entity. Prior to September 1, 2010, we consolidated the operations of Keystone Midstream, where the noncontrolling interest’s share of net loss was recorded as Net Loss Attributable to Noncontrolling Interests. Our share of net income and net loss realized under the equity method of accounting are primarily due to project management costs, general and administrative expenses, and DD&A expenses and totaled approximately $3.2 million of net loss, $0.5 million of net income and $0.1 million of net loss for the period ended May 29, 2012, for the year ended December 31, 2011 and for the four-month period ended December 31,2010, respectively.

8. CONCENTRATIONS OF CREDIT RISK

At times during the years ended December 31, 2012 and 2011, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with four high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our Senior Credit Facility. We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled settlement date. For additional information, see Note 2, Summary of Significant Accounting Policies, and Note 12, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2012, we carried approximately $18.1 million in production receivables, of which approximately $16.3 million were production receivables due from four purchasers. At December 31, 2011, we carried approximately $13.6 million in production receivable, of which approximately $12.9 million were production receivables due from three purchasers. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.

9. 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.

As of December 31, 2012 and 2011, we did not have any reserves established for future legal obligations. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we currently believe that no reserve is needed, 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 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 future losses that are not currently accrued. Based on currently available information, we believe that it is remote that future costs, if any, 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.

Environmental

Due to the nature of the natural gas and oil business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages 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 conducting evaluations (both internal and using consultants) to identify existing problems and assessing the potential liability. Except for contingent liabilities associated with the consent decree with the U.S. EPA relating to alleged H₂S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

We have posted $0.8 million, at December 31, 2012 and December 31, 2011, in various letters of credit to secure our drilling and related operations.

Lease Commitments

At December 31, 2012 we have lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.3 million, $0.4 million and $0.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands).


2013	$	551
2014		463
2015		420
2016		420
2017		420
Thereafter		0

Total	$	2,274

Capacity Reservation

In connection with our sale of Keystone Midstream (see Note 7, 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 by MarkWest to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $6.1 million in 2013, $10.4 million in 2014, $13.0 million in 2015, $14.6 million in 2016, $14.6 million in 2017 and $115.3 million thereafter. For the years ended December 31, 2010, 2011 and 2012, we incurred capacity reservation charges of

$0 million, $0.1 million and $0.5, respectively, which is consistent with our estimated working interest in this project area of approximately 70.0%. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations.

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 $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 came to terms on contracted completion services in the Appalachian Basin. The minimum cost to retain the completion services is approximately $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 Agreements

During the normal course of business we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $406.4 million, which is larger than our estimated minimum obligations due to certain contracts which have minimum commitment volumes and other contracts which contain provisions that require payment on all volumes delivered.

For the years ended December 31, 2012, 2011 and 2010, we incurred expenses related to the transportation and marketing our oil, natural gas and natural gas liquids of approximately $9.0 million, $4.6 million and $0.1 million, respectively.

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


	Total
2013	$	8,411
2014		12,495
2015		19,584
2016		26,712
2017		32,552
Thereafter		341,576

Total	$	441,330

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 December 31, 2012, the remaining drilling carry obligation balance was approximately $11.3 million.

In addition to the drilling carry obligation, we are required to meet certain drilling commitments. Amounts incurred toward the attainment of the drilling commitments are credited towards the drilling carry obligation. Our drilling commitments require us 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. 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 natural 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 natural gas well is determined using the following matrix, with vertical unconventional natural gas wells being charged 20% of the applicable rates:


	<$2.25(a)		$2.26 - $2.99(a)		$3.00 - $4.99(a)		$5.00 - $5.99(a)		>$5.99(a)
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

(b)	Pricing utilized for determining annual fees 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 twelve months ended December 31, 2012, we incurred approximately $5.4 million in fees related to the natural gas impact fee. Of this amount, approximately $2.8 million was related to the first year fees for unconventional gas wells drilled prior to 2012. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.

Other

In addition to the asset retirement obligation discussed in Note 2, Summary of Significant Accounting Policies, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts, totaling $0.3 million, are included in Other Deposits and Liabilities at December 31, 2012 and December 31, 2011, respectively.

10. RELATED PARTY TRANSACTIONS

Aircraft Services

We have an oral month-to-month agreement with Charlie Brown Air Corp. (“Charlie Brown”), a New York corporation owned by Lance T. Shaner, our Chairman, regarding the use of two airplanes owned or managed on our behalf by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate that ranges from $400 to $1,850 per hour. In September 2010, we purchased an undivided 50% interest in one of these airplanes, a Cessna model 550 from Charlie Brown for approximately $0.6 million. In April 2011, we purchased the remaining 50% interest in

this aircraft for approximately $0.6 million. The purchase of the aircraft has been recorded as Other Property and Equipment on our Consolidated Balance Sheets. For the years ended December 31, 2011 and 2010, we paid Charlie Brown $0.2 million and $0.4 million, respectively, for the use of the aircrafts, including the variable per hour cost in addition to pilots fees, maintenance, hangar rental and other miscellaneous expenses. For the year ended December 31, 2012, the amounts paid to Charlie Brown were negligible.

We own a 25% membership interest in Charlie Brown Air II, LLC (“Charlie Brown II”). Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Lance T. Shaner (“Shaner Hotel”), and an unrelated third party each own 25% and 50%, respectively, in Charlie Brown II, which owns and operates an Eclipse 500 aircraft, which was purchased for approximately $1.7 million.

Charlie Brown II has a loan from Susquehanna Bank, formerly Graystone Bank, to purchase the aircraft that was originally $1.5 million at its inception in June 2007. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan required payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II has been required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The Company and Shaner Hotel each guarantee up to twenty five percent, or $0.4 million, of the principal balance of the loan. The balance of this loan as of December 31, 2012 and 2011 was approximately $1.3 million and $1.4 million, respectively. For the years ended December 31, 2012, 2011 and 2010, we paid Charlie Brown II approximately $0.2 million each year, respectively, for loan interest, services rendered and retainer fees.

The business affairs of Charlie Brown Air II, LLC are managed by three members, appointed by each of its three owners. We have designated Thomas C. Stabley, our Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown Air II, LLC, require the written consent of all managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company.

Office Rental

On June 27, 2012, we entered into an office lease agreement with Shaner Office Holdings, L.P., a limited partnership controlled by Lance T. Shaner. The office lease, which will replace our existing headquarters office lease in State College, Pennsylvania, calls for monthly rental payments in the amount of $35,000 beginning on April 1, 2013 and ending on December 31, 2017, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The term of the lease may be extended for up to three five-year extensions or the property may be purchased outright by our exercise of a purchase option at the end of thefive-year lease term. We will account for this lease as an operating lease, subsequently recording the rental payments as General and Administrative Expense on our Consolidated Statements of Operations.

RW Gathering, LLC

We own a 40% interest in RW Gathering which owns gas-gathering assets to facilitate the development of our joint operations with WPX and Sumitomo (see Note 7, Equity Method Investments, to our Consolidated Financial Statements). For the years ended December 31, 2012, 2011 and 2010, we incurred approximately $0.8 million, $0.8 million and $0.2 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2012, 2011 and 2010, there were no receivables or payables in relation to RW Gathering due to or from us.

Keystone Midstream

We incurred approximately $2.4 million, $4.6 million and $0.3 million in transportation and processing expenses that were charged to us from Keystone Midstream during 2012, 2011 and 2010, respectively (see Note 7, Equity Method Investments, to our Consolidated Financial Statements). Prior to September 1, 2010, charges incurred for transportation were eliminated in consolidation. Subsequent to September 1, 2010, such transportation charges are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations. We sold our ownership interest in Keystone Midstream in May 2012, resulting in no amounts due to or from Keystone Midstream as of December 31, 2012. As of December 31, 2011, we had Accrued Expenses due to Keystone Midstream of approximately $0.5 million, which was inclusive of transportation and processing expenses incurred during December 2011.

Water Solutions

We incurred approximately $3.2 million, $1.6 million and $0.4 million in gross water transfer and water purification expenses that were charged to us from Water Solutions during 2012, 2011 and 2010, respectively (see Note 6, Consolidated Subsidiaries, to our Consolidated Financial Statements). Of the amounts incurred, we have eliminated approximately $2.2 million, $1.0 million and $0.4 million in consolidation for the years 2012, 2011 and 2010, respectively. As of December 31, 2012, 2011 and 2010, we had payables of approximately $0.2 million, $0.3 million and $0 to Water Solutions for work performed during the period.

NorthStar #3, LLC

During 2011, we paid approximately $4.9 million in expenses related to the drilling of a water disposal well on behalf of NorthStar #3 (see Note 6, Consolidated Subsidiaries, to our Consolidated Financial Statements). This amount has been recorded in a promissory note due to us from NorthStar #3. During 2012, we received approximately $0.3 million in refunds and reimbursements on expenditures previously incurred, decreasing the amount of the promissory note to approximately $4.6 million. The promissory note has been eliminated in consolidation, while the cost of the well has been recorded as Wells and Facilities in Progress on our Consolidated Balance Sheet. As of December 31, 2012 and 2011, there were no amounts due to NorthStar #3 or due to us from NorthStar #3 with exception to the promissory note. NorthStar #3 did not exist prior to 2011.

11. LONG-TERM DEBT

Senior Credit Facility

We maintain a revolving credit facility evidenced by the Credit Agreement, dated September 28, 2007, with KeyBank, as Administrative Agent; and lenders from time to time parties thereto (as amended from time to time, the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base under the Senior Credit Facility is currently $240.0 million; however, the revolving credit facility may be increased to up to $500 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base. As of December 31, 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 December 31, 2012, we did not have any amounts outstanding under 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 Alternative Base Rate (as defined below) plus, in each case an applicable per annum margin. The applicable per annum margin is determined based upon our total borrowing base utilization percentage in accordance with a pricing grid. The applicable per annum margin ranges from 1.75% to 2.75% for Eurodollar loans and .50% to 1.50% for ABR loans. The Adjusted Base Rate is equal to the greater of: (i) KeyBank’s announced prime rate; (ii) the federal funds effective rate from time to time plus 1 / 2 of 1%; and (iii) 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%.

Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.

The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; enter into transactions with affiliates; create or acquire additional subsidiaries; incur indebtedness; sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions (for further information, see Note 2, Summary of Significant Accounting Policies, Note 8, Concentrations of Credit Risk, and Note 12, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements). 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 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, 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, 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, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of December 31, 2012 was approximately 6.0 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 current quarter on an annualized basis to interest expense for such period, known as our interest coverage ratio, must not be less than 3.0 to 1.0. Our interest coverage ratio as of December 31, 2012 was approximately 14.7 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the current quarter on an annualized basis must not exceed 4.25 to 1.0. Our ratio of total debt to EBITDAX as of December 31, 2012 was approximately 2.4 to 1.0.

Second Lien Credit Agreement

On December 22, 2011, we entered into a second lien credit agreement (as amended from time to time, 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 provided for a $100.0 million senior secured second lien term loan facility under which $50.0 million was initially available to us and up to an additional $50.0 million of incremental borrowings may be available upon the request of the Company. During December 2012, we repaid in full, and terminated, the Second Lien Credit Agreement. As of December 31, 2011, we had $50.0 million drawn on the Second Lien Credit Agreement.

Senior Notes

On December 12, 2012, we issued a $250.0 million aggregate principal amount of 8.875% senior notes in a private offering at an issue price of 99.3% due to mature on December 1, 2020 (the “Notes”). The net proceeds of the Notes, after discounts and expenses, were approximately $242.2 million. Debt issuance costs of $6.1 were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the notes as Interest Expense on our Consolidated Statement of Operations. Interest is payable semi-annually at a rate of 8.875% per annum on June 1 and December 1 of each year, commencing on June 1, 2013.

We may redeem, at specified redemption prices, some or all of the Notes at any time on or after December 1, 2016. We may also redeem up to 35% of the notes using the proceeds of certain equity offerings completed before December 1, 2015. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the notes from holders. The Notes will be fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries.

In addition to our Senior Credit Facility and our Notes, we may, from time to time in the normal course of business, finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and lines of credit consists of the following at December 31, 2012 and 2011:


	December 31, 2012 (in thousands)			December 31, 2011 (in thousands)
8.875% Senior Notes	$	250,000		$	0
Discount on Senior Notes		(1,742	)		0
Senior Lines of Credit and Second Lien(a)		0			225,000
Capital Leases and Other Obligations(a)		2,677			544

Total Debt		250,935			225,544
Less Current Portion of Long-Term Debt(b)		(1,686	)		(406	)

Total Long-Term Debt	$	249,249		$	225,138

(a)

The average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2012 and 2011 was approximately 2.5%. The average interest rate on borrowings under the Second Lien Credit Agreement for the year ended December 31, 2012 and 2011 was approximately 7.3% and 8.3%, respectively. The average interest rate on our Other Loans and Notes Payable as of December 31, 2012 and 2011 was approximately 4.5% and 2.3%, respectively.

(b)	Classified as Accounts Payable on our Consolidated Balance Sheets.

The following is the principal maturity schedule for debt outstanding as of December 31, 2012:


	Year Ended December 31, (in thousands)
2013	$	1,686
2014		378
2015		351
2016		262
2017		0
Thereafter		250,000

Total	$	252,677

12. FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of December 31, 2012, 2011 and 2010, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain on Derivatives, Net. For additional information, see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements.

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 with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 8, Concentrations of Credit Risk, to our Consolidated Financial Statements.

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

We received net cash settlements of $16.2 million, $6.2 million and $0.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Unrealized gains and losses from continuing operations associated with our derivative instruments amounted to a loss of $5.5 million, a gain of $12.7 million and a gain of $6.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The following table summarizes the location and amounts of gains and losses on derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010:


	Year Ended December 31, 2012 (in thousands)
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustments	$	0		$	2,138		$	2,138
Mark-to-market fair value adjustments		0			(273	)		(273	)
Settlement of contracts(a)		(286	)		0			(286	)

Crude Oil Total		(286	)		1,865			1,579
*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			(10,404	)		(10,404	)
Mark-to-market fair value adjustments		0			2,471			2,471
Settlement of contracts(a)		16,095			0			16,095

Natural Gas Total		16,095			(7,933	)		8,162
*Natural Gas Liquids*
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			0			0
Mark-to-market fair value adjustments		0			536			536
Settlement of contracts(a)		410			0			410

Natural Gas Liquids Total		410			536			946

Gain (Loss) on Derivatives, Net	$	16,219		$	(5,532	)	$	10,687

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


	Year Ended December 31, 2011 (in thousands)
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustments	$	0		$	1,850		$	1,850
Mark-to-market fair value adjustments		0			(1,488	)		(1,488	)
Settlement of contracts(a)		(670	)		0			(670	)

Crude Oil Total		(670	)		362			(308	)
*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			(4,231	)		(4,231	)
Mark-to-market fair value adjustments		0			16,573			16,573
Settlement of contracts(a)		6,882			0			6,882

Natural Gas Total		6,882			12,342			19,224
Gain (Loss) on Derivatives, Net	$	6,212		$	12,704		$	18,916

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


	Year Ended December 31, 2010 (in thousands)
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustments	$	0		$	5,782		$	5,782
Mark-to-market fair value adjustments		0			(2,819	)		(2,819	)
Settlement of contracts(a)		(3,861	)		0			(3,861	)

Crude Oil Total		(3,861	)		2,963			(898	)
*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			(1,925	)		(1,925	)
Mark-to-market fair value adjustments		0			4,211			4,211
Settlement of contracts(a)		4,667			0			4,667

Natural Gas Total		4,667			2,286			6,953
*Interest Rate*
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			711			711
Mark-to-market fair value adjustments		0			0			0
Settlement of contracts(a)		(711	)		0			(711	)

Interest Rate Total		(711	)		711			0
Gain (Loss) on Derivatives, Net	$	95		$	5,960		$	6,055

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

Our derivative instruments are recorded on the balance sheet as either an asset, or a liability, measured at its fair value. The fair value associated with our derivative instruments was an asset of approximately $9.8 million and $15.3 million at December 31, 2012 and 2011, respectively.

Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2012 consisted of:


Period	Volume		Put Option		Floor		Ceiling		Swap		Fair Market Value ($ in Thousands)
Oil
2013—Collar		540,000 Bbl	$	0	$	72.44	$	112.56	$	0	$	(217	)
2013—Swap		120,000 Bbl		0		0		0		91.41		(217	)
2013—Three Way Collar		60,000 Bbl		65.00		80.00		100.00		0		(45	)
2014—Three Way Collar		360,000 Bbl		65.00		82.33		104.27		0		(509	)

		1,080,000 Bbl									$	(988	)
Natural Gas
2013—Swap		6,570,000 Mcf	$	0	$	0	$	0	$	3.84	$	1,631
2013—Three Way Collar		2,520,000 Mcf		3.35		4.17		4.88		0		986
2013—Collar		3,360,000 Mcf		0		4.77		5.68		0		4,211
2013—Put		2,640,000 Mcf		0		5.00		0		0		3,378
2013—Swaption		1,200,000 Mcf		0		0		0		4.50		354
2014—Call		1,800,000 Mcf		0		0		5.00		0		(366	)
2014—Three Way Collar		4,800,000 Mcf		2.91		3.91		4.68		0		430
2014—Swap		2,400,000 Mcf		0		0		0		3.84		(195	)
2014—Collar		1,800,000 Mcf		0		3.51		4.43		0		(166	)

		27,090,000 Mcf									$	10,263
Natural Gas Liquids
2013—Swap		108,000 Bbl	$	0	$	0	$	0	$	43.26	$	535

		108,000 Bbl									$	535

The combined fair value of derivatives included in our Consolidated Balance Sheets as of December 31, 2012 and December 31, 2011 is summarized below.


	December 31, 2012 (in thousands)			December 31, 2011 (in thousands)
Short-Term Derivative Assets:
Crude Oil—Collars	$	90		$	0
Natural Gas Liquids—Swaps		535			0
Natural Gas—Swaps		2,416			3,912
Natural Gas—Swaption		354			1,047
Natural Gas—Three Way Collars		1,021			1,333
Natural Gas—Collars		4,211			4,112
Natural Gas—Puts		3,378			0

Total Short-Term Derivative Assets	$	12,005		$	10,404

Long-Term Derivative Assets:
Crude Oil—Collars	$	0		$	143
Natural Gas—Swaps		239			1,377
Natural Gas—Collars		0			5,690
Natural Gas—Three Way Collars		465			861
Natural Gas—Puts		0			505

Total Long-Term Derivative Assets	$	704		$	8,576

Total Derivative Assets	$	12,709		$	18,980

Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(307	)	$	(2,363	)
Crude Oil—Swaps		(217	)		0
Crude Oil—Three Way Collars		(45	)		0
Natural Gas—Three Way Collars		(35	)		0
Natural Gas—Swaps		(785	)		0

Total Short-Term Derivative Liabilities	$	(1,389	)	$	(2,363	)

Long-Term Derivative Liabilities:
Crude Oil—Three Way Collars	$	(509	)	$	(632	)
Natural Gas—Swaps		(434	)		0
Natural Gas—Three Way Collars		(35	)		0
Natural Gas—Call		(366	)		0
Natural Gas—Collars		(166	)		(643	)

Total Long-Term Derivative Liabilities	$	(1,510	)	$	(1,275	)

Total Derivative Liabilities	$	(2,899	)	$	(3,638	)

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

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

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

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

The following table presents the fair value hierarchy table for assets and liabilities measured at fair value ($ in thousands):


	Fair Value Measurements at December 31, 2012 Using:
	Total Carrying Value as of December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivatives(a)	$	9,810	$	0	$	9,810	$	0
Asset Retirement Obligations	$	24,822	$	0	$	0	$	24,822

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

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 December 31, 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 December 31, 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 December 31, 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; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances which represent the entirety of our Level 3 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:


	December 31, 2012				December 31, 2011
In thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
8.875% Senior Notes, Net of Discount	$	248,258	$	249,074	$	0	$	0
Secured Lines of Credit		0		0		225,000		225,000
Capital Leases and Other Obligations		2,677		2,524		544		511

Total	$	250,935	$	251,598	$	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. We measure the fair value of our senior notes using pricing that is readily available in the public market. Accordingly, the fair value of our senior notes would be classified as Level 2 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.

13. INCOME TAXES

We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Our income tax expense from continuing operations consisted of the following:


	For the Years Ended December 31,
(in thousands)	2012		2011			2010
Current:
Federal	$	2,329	$	63		$	11
State		5,825		244			292
Deferred:
Federal		28,216		8,524			4,741
State		2,179		(561	)		456

Income Tax Expense	$	38,549	$	8,270		$	5,500

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


	Year Ended December 31, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010
Income before noncontrolling interests and income taxes	$	94,971		$	26,358		$	13,558
Statutory U.S. income tax rate		35.0	%		35.0	%		35.0	%

Tax expense recognized using statutory U.S. income tax rate	$	33,240		$	9,225		$	4,745
Change in estimated future state rate		(7	)		612			77
Permanent differences		52			176			33
Change in valuation allowance		(131	)		1,031			0
Other		(493	)		(4,092	)		52

Adjusted federal income tax expense	$	32,661		$	6,952		$	4,907
State income tax expense		5,888			1,318			593

Total income tax expense	$	38,549		$	8,270		$	5,500

Effective income tax rate		40.6	%		31.4	%		40.6	%

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2012 and 2011:


	For the Years Ended December 31,
(in thousands)	2012			2011
Tax effects of temporary differences for:
Current:
Assets:
G&G amortization	$	0			1,020
Future sale proceeds held in escrow		2,947			0
Non-cash compensation plans		714			0
Valuation allowance		0			(175	)
Other		306			329

Total current deferred tax assets		3,967			1,174
Liabilities:
Unrealized gain on derivatives		(4,365	)		(3,315	)
Other		(141	)		0

Total current deferred tax liabilities		(4,506	)		(3,315	)

Net total current deferred tax liability		(539	)		(2,141	)

Long-Term:
Assets:
Asset retirement obligation		10,211			7,704
Valuation allowance		(1,732	)		(1,688	)
Non-cash compensation plans		2,090			2,095
Net operating loss carryforward		4,384			15,714
Organization costs		689			763
Deferred revenue		1,487			0
AMT credits		1,380			74
Other		593			301

Total long-term deferred tax assets		19,102			24,963
Liabilities:
Unrealized gain on derivatives		0			(3,010	)
Timing differences—tax partnerships		(5,873	)		(1,818	)
Book basis of oil and gas properties in excess of tax basis		(36,805	)		(18,434	)
Other		(49	)		(58	)

Total long-term deferred tax liabilities		(42,727	)		(23,320	)

Net total long-term deferred tax asset (liability)		(23,625	)		1,643

Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. These deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2012, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it was necessary to provide a valuation allowance of approximately $1.7 million for statutory depletion carryforwards and charitable contributions. Based on the expected patterns of reversal of all existing temporary differences, we have concluded that it is more likely than not that the remaining deferred tax assets will be realized. As of December 31, 2011, we recorded a valuation allowance of approximately $1.9 million for statutory depletion carryforwards and charitable contributions.

Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances.

At December 31, 2012, we had available unused federal net operating loss carryforwards of $1.7 million that may be applied against future taxable income that expire in 2031. The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected):


Year of Expiration	Net Operating Loss Carryforwards (in thousands)
2020	$	58
2021		259
2022		64
2023		0
2024		1,091
2025		0
2026		0
2027		0
2028		0
2029		0
2031		2,912

Total		4,384

FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position.

Our management has concluded that, as of December 31, 2012, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no liability balance is required to offset any unsustainable positions. We did not have any accrued interest or penalties as of December 31, 2012 and 2011.

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

14. EARNINGS PER COMMON SHARE

Basic income (loss) 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 and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the year ended December 31, 2012, we excluded 432,790 stock options from the computation of diluted earnings per share because their effect would have been anti-dilutive. For the year ending December 31, 2011, we excluded 603,064 stock options from the computation of diluted earnings per share because their effect would have been anti-dilutive. Stock options of 715,106 for the year ending December 31, 2010 were outstanding but not included in the computations of diluted net income per share

because their effect would be anti-dilutive (for additional information on our non-cash compensation plans, see Note 17, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data):


	Year Ended December 31, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010
Numerator (in thousands):
Net Income (Loss) From Continuing Operations	$	56,422		$	18,088		$	8,058
Net Income (Loss) From Discontinued Operations		(10,943	)		(33,457	)		(2,022	)

Net Income (Loss)	$	45,479		$	(15,369	)	$	6,036

Denominator (in thousands):
Weighted Average Common Shares Outstanding—Basic		51,543			43,930			43,281
Effect of Dilutive Securities:
Employee Stock Options		69			95			112
Employee Performance-Based Restricted Stock Awards		413			451			277

Weighted Average Common Shares Outstanding—Diluted		52,025			44,476			43,670

Earnings per Common Share(a):
Basic—Net Income (Loss) From Continuing Operations	$	1.09		$	0.41		$	0.18
—Net Income (Loss) From Discontinued Operations		(0.21	)		(0.76	)		(0.05	)

—Net Income (Loss)	$	0.88		$	(0.35	)	$	0.13

Diluted—Net Income (Loss) From Continuing Operations	$	1.08		$	0.41		$	0.18
—Net Income (Loss) From Discontinued Operations		(0.21	)		(0.76	)		(0.05	)

—Net Income (Loss)	$	0.87		$	(0.35	)	$	0.13

(a)	All earnings per share amounts are attributable to Rex common shareholders.

15. CAPITAL STOCK

Currently, our common stock is traded on the NASDAQ Global Select Market under the trading symbol “REXX”. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. In February 2012, we completed a public offering of 8,050,000 shares of common stock at an offering price of $9.25 per share. The net proceeds from the offering were approximately $70.6 million, after deducting underwriting discounts, commissions and offering expenses. We used a portion of the proceeds to repay 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. As of December 31, 2012 and 2011, we had 53,213,264 and 44,859,220 shares of common stock outstanding, respectively.

16. MAJOR CUSTOMERS

For the year ended December 31, 2010, approximately $62.0 million, or 92.2%, of our commodity sales from continuing operations were derived from five customers, with the largest customer being responsible for approximately $51.9 million, or 77.2%, of total commodity sales. For the year ended December 31, 2011, approximately $103.6 million, or 92.6%, of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $62.9 million, or 56.2%. For the year ended December 31, 2012, approximately $128.3 million, or 95.3% of our commodity sales from continuing operations were attributable to five customers with the largest single purchaser accounting for $64.7 million, or 48.1%.

17. EMPLOYEE BENEFIT AND EQUITY PLANS

401(k) Plan

We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Our contributions to the plan attributable to continuing operations were approximately $0.5 million, $0.4 million and $0.3 million for the years ended December 31, 2012, 2011 and 2010, 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 where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as a financing cash flow, rather than as an operating cash flow.

2007 Long-Term Incentive Plan

We have granted stock options, stock appreciation rights and restricted stock awards to various employees, non-employee directors and non-employee contractors under the terms of our 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees may be designed, at the Compensation Committee’s discretion, to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes. The Compensation Committee has authorized the issuance of 3,079,470 shares under the Plan, with 813,475 and 929,635 still available as of December 31, 2012 and 2011, respectively.

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

Stock Options

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

During the year ended December 31, 2012, we did not issue options to purchase shares of our common stock. During the year ended December 31, 2011, the Compensation Committee awarded nonqualified options to

purchase a total of 90,074 shares of our common stock to three employees. The nonqualified stock options granted to our employees during 2011 have an exercise price equal to the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant, and vest and become exercisable in one-third increments on the first, second or third anniversary of the grant date, provided that the option holder remains our employee until that date. All options also provide that all unvested options vest and become immediately exercisable upon a “change in control” of us; as that term is defined in the Plan.

A summary of the stock option activity is as follows:


	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Term (in years)		Aggregate Intrinsic Value (in thousands)
Options outstanding December 31, 2009		873,837		$	13.41
Granted		111,174			11.83
Exercised		(22,000	)		9.99
Cancelled/Forfeited		(136,500	)		18.18

Options Outstanding December 31, 2010		826,511		$	12.50
Granted		90,074			12.74
Exercised		(139,682	)		9.75
Cancelled/Forfeited		(78,576	)		13.75

Options Outstanding December 31, 2011		698,327		$	12.94
Granted		0			0
Exercised		(52,287	)		10.80
Cancelled/Forfeited		(143,787	)		20.71

Options Outstanding December 31, 2012		502,253		$	10.95		4.6	$	1,406

Options Exercisable December 31, 2012		427,513		$	10.64		4.9	$	1,374

Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2012, 2011 and 2010 totaled $0.2 million, $0.7 million and $1.0 million, 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 years ended December 31, 2012, 2011 and 2010 was $0.1 million, $0.3 million and $0.1 million, respectively. The total tax benefit for the years ended December 31, 2012, 2011 and 2010 was negligible.

The fair value of each option grant is estimated on the date of the grant using the Black-Scholes option-pricing model with the following assumptions:


	For the Years Ended December 31,
	2011			2010
Expected Dividend Yield		0	%		0	%
Expected Stock Price Volatility		74.7	%		90.0	%
Risk-Free Interest Rate		0.63	%		1.66	%
Expected Life of Options (Years)		4			4-6.5

The dividend yield of zero is based on the fact that we have never paid cash dividends on common stock and have no present intention of doing so. Our expected historical volatility factor was determined by assessing the common stock trading history of eight publicly-traded oil and gas companies that we determined to be similar to us in ways such as their operating strategy, capital structure, production mix and volume and asset size in addition to our own historical volatility. The risk-free interest rate was determined by interpolating the average yield on a U.S. Treasury bond for a period approximately equal to the expected average life of the options. The

average expected life has been determined using the “simplified method” in which the average expected life of the option is equal to the average of the term of the option and the vesting period. We elected to use the simplified method for determining the average expected life because we do not have a history on which to base estimates for the term to exercise of our granted stock options.

Based on the above assumptions, the weighted average estimated fair value of options granted during the years ended December 31, 2011 and 2010 was $6.06 per share and $6.74 per share, respectively. The weighted average exercise price of options granted during 2011 and 2010 was $12.78 and $11.83, respectively.

A summary of the status of our issued and outstanding stock options as of December 31, 2012 is as follows:


	Outstanding						Exercisable
Exercise Price	Number Outstanding at 12/31/12		Weighted Average Remaining Contractual Life (Years)		Weighted Average Exercise Price		Number Exercisable at 12/31/12		Weighted Average Exercise Price
$5.04		46,041		6.3	$	5.04		46,041	$	5.04
$9.50		100,000		4.9	$	9.50		100,000	$	9.50
$9.99		196,499		4.8	$	9.99		196,499	$	9.99
$10.42		29,548		7.5	$	10.42		19,699	$	10.42
$11.87		3,500		3.3	$	11.87		1,166	$	11.87
$12.50		19,139		2.9	$	12.50		12,758	$	12.50
$13.01		18,526		2.8	$	13.01		12,350	$	13.01
$13.19		50,000		3.8	$	13.19		0	$	0
$19.92		5,000		0.6	$	19.92		5,000	$	19.92
$22.34		30,000		5.3	$	22.34		30,000	$	22.34
$23.28		4,000		0.5	$	23.28		4,000	$	23.28

Total		502,253		4.6	$	10.95		427,513	$	10.64

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2012 were 4.6 years and $1.4 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at December 31, 2011 were 4.7 years and $2.5 million, respectively. As of December 31, 2012, unrecognized compensation expense related to stock options totaled approximately $0.3 million, which will be recognized over a weighted average period of 1.6 years.

Restricted Stock Awards

During the year ended December 31, 2012, the Compensation Committee issued 425,209 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. During the year ended December 31, 2011, the Compensation Committee issued 709,890 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2012 and 2011 are subject to time vesting and, in some cases, performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date until the date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse for performance-based awards to varying degrees based on performance metrics at the time of the change in control. For awards that do not contain a performance-based condition, all restrictions immediately lapse upon a change in control. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period.

Certain of the restricted common stock awards in 2012 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group of 13 companies over a three-year period. The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:


TSR Rank	Percentage of Awards to Vest
1 – 3		100	%
4 – 5		75	%
6 – 8		50	%
9 – 11		25	%
12 – 14		0	%

The fair value of the TSR awards of $7.80 per share was estimated on the date of the grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:


	Year Ended December 31, 2012
Expected Dividend Yield		0.0	%
Risk-Free Interest Rate		0.3	%
Expected Volatility—Rex Energy		54.4	%
Expected Volatility—Peer Group		31.2%-58.6	%
Market Index		37.0	%
Expected Life		Three Years

The dividend yield of zero reflects the fact that we have never paid cash dividends on our common stock and have no present intentions of doing so. The risk-free interest rate reflects the U.S. Treasury Constant Maturity rates as of the measurement date, converted into an implied “spot rate” yield. Our expected volatility estimates are based on observed historical volatility of daily stock returns for the three-year period preceding the grant date. Market index is an equal-weight index of the companies in the peer group. Expected life is measured as the grant date through the end of the performance period. Performance and market 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. Compensation expense for the TSR awards is recognized on a straight-line basis over the vesting period.

We recorded compensation expense related to restricted common stock awards of $2.9 million, $0.9 million and $0.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. As of December 31, 2012, total unrecognized compensation cost related to the restricted common stock grants was approximately $4.3 million to be recognized over a weighted average of 2.1 years. The total fair value of restricted common stock awards that vested in 2012 was approximately $0.7 million. There were no restricted stock vestings prior to 2012.

A summary of the restricted stock activity for the years ended December 31, 2012, 2011 and 2010 is as follows:


	Number of Shares			Weighted- Average Grant Date Fair Value
Restricted stock awards, as of January 1, 2010		248,100		$	3.74
Awards		860,563			12.07
Forfeitures		(293,698	)		7.99

Restricted stock awards, as of December 31, 2010		814,965		$	11.01
Awards		757,816			13.07
Forfeitures		(342,955	)		11.60

Restricted stock awards, as of December 31, 2011		1,229,826		$	12.11
Awards		425,209			11.59
Vested		(70,750	)		2.05
Forfeitures		(152,712	)		12.13

Restricted stock awards, as of December 31, 2012		1,431,573		$	12.45

18. IMPAIRMENT EXPENSE

For the years ended December 31, 2012, 2011 and 2010, we incurred impairment expense from continuing operations of approximately $20.6 million, $14.6 million and $8.9 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 (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). During 2012, we incurred approximately $13.7 million of expense related to the impairment of proved unconventional natural gas wells in the Appalachian Basin, which in part was driven by the continued low natural gas pricing environment. All of the proved unconventional natural gas wells that were impaired produce dry natural gas and are located in both our operated and non-operated areas in the Appalachian Basin. In addition to the impairment related to our natural gas properties, we incurred approximately $5.8 million in impairment expense primarily related to the expected future expiration or surrender of undeveloped acreage in our non-operated dry gas area of Clearfield County, Pennsylvania. The remaining impairment was due to three non-operated properties in the Illinois Basin. During 2011, we incurred approximately $11.6 million of expense related to the impairment of proved conventional shallow natural gas wells in the Appalachian Basin. In addition to the impairment related to our conventional shallow natural gas properties, we incurred approximately $1.4 million in impairment expense related to the expiration or surrender of undeveloped acreage and $1.6 million in impairment expense related to a refrigeration plant in the Appalachian Basin which was formerly in use before the commencement of operations at the cryogenic gas processing plants in Butler County, Pennsylvania. With larger scale gas processing capabilities in the region there is no further value for the refrigeration plant. During 2010, we determined that the carrying values of two of our test wells in Clearfield County, Pennsylvania, which were in various stages of drilling and completion, and did not hold proved reserves, were not recoverable due to a lack of a sales outlet and no current plans by us to complete the wells for commercial production. The carrying value of these wells before impairment was approximately $3.9 million. In addition, we incurred approximately $2.3 million in impairment expense related to the expiration or surrender of undeveloped acreage.

19. SUSPENDED EXPLORATORY WELL COSTS

We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for the years ended December 31, 2012, 2011 and 2010 ($ in thousands):


	2012			2011			2010
Beginning Balance at January 1,	$	11,756		$	1,637		$	5,107
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves		95,980			106,045			34,330
Divested wells		0			0			(10,770	)
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves		(70,518	)		(95,926	)		(23,016	)
Capitalized exploratory well costs charged to expense		(250	)		0			(4,014	)

Ending Balance at December 31,		36,968			11,756			1,637
Less exploratory well costs that have been capitalized for a period of one year or less		(36,630	)		(11,756	)		(1,637	)

Capitalized exploratory well costs for a period of greater than one year	$	338		$	0		$	0
Number of projects that have exploratory well costs capitalized for a period of more than one year		2			0			0

As of December 31, 2012 we had approximately $0.3 million in capitalized exploratory well costs that were capitalized for a period greater than one year. These costs are related to two wells in our operated region in Butler County, Pennsylvania in the Appalachian Basin. These costs represent preliminary permitting and engineering expenses that we typically incur several months in advance of commencing drilling operations. Both wells are scheduled for completion activity in 2013, at which time they will be reclassified to Evaluated Oil and Gas Properties upon the discovery of proved reserves or to Exploration Expense if commercial quantities of reserves are not found.

20. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (UNAUDITED)

Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands):


	2012		2011		2010
Consolidated Entities:
Acquisition of Properties
Proved	$	1,474	$	9	$	53
Unproved		49,331		76,852		43,166
Exploration Costs		128,748		113,075		36,008
Development Costs(a)		57,149		61,920		24,825

Subtotal		236,702		251,856		104,052
Asset Retirement Obligations		4,480		316		186

Total Costs Incurred	$	241,182	$	252,172	$	104,238
Share of Equity Method Investments:
Acquisition of Properties
Proved	$	0	$	0	$	0
Unproved		0		0		0
Exploration Costs		0		0		0
Development Costs(a)		4,316		12,682		6,018

Total	$	4,316	$	12,682	$	6,018

(a)	Includes Depreciation expense for support equipment and facilities.

The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands):


	2012			2011			2010
Total Costs Incurred by Consolidated Entities	$	241,182		$	252,172		$	104,238
Equity Method Investments		4,087			23,204			8,721
DJ Basin Expenditures		3,146			24,029			45,659
Exploration Expense		(4,782	)		(2,507	)		(2,578	)
Asset Retirement Obligations		(4,480	)		(316	)		(186	)
Depreciation for Support Equipment and Facilities		(4,187	)		(3,308	)		(2,948	)
Other		3,888			9,142			11,634

Total Capital Expenditures	$	238,854		$	302,416		$	164,540

21. OIL AND NATURAL GAS CAPITALIZED COSTS (UNAUDITED)

Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands):


	2012			2011
Consolidated Entities:
Proven Oil and Natural Gas Properties	$	485,448		$	349,938
Pipelines and Support Equipment		31,231			30,926
Field Operation Vehicles and Other Equipment		13,412			9,489
Wells and Facilities in Progress		91,685			61,355
Unproven Properties		161,618			123,241

Total		783,394			574,949
Less Accumulated Depreciation and Depletion		(141,769	)		(104,894	)

Total	$	641,625		$	470,055
Share of Equity Method Investments:
Pipelines and Support Equipment	$	17,524		$	25,344
Field Operation Vehicles and Other Equipment		0			36
Wells and Facilities in Progress		26			16,637

Total		17,550			42,017
Less Accumulated Depreciation and Depletion		(1,077	)		(1,817	)

Total	$	16,473		$	40,200

22. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

Our independent engineers, Netherland, Sewell, and Associates, Inc. (“NSAI”) evaluated all of our proved oil, natural gas and NGL reserves for the years ended December 31, 2012, 2011 and 2010. The technical persons responsible for preparing the estimates of our estimated proved reserves meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil, natural gas and NGL reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our estimated proved reserves are located within the United States.

Proved oil, natural gas and NGL reserves represent the estimated quantities of oil, natural gas and NGLs which geoscience and engineering data demonstrate with reasonable certainty will be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and governmental regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed oil, natural gas and NGL reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Estimated proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated unless such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. We have approximately two gross (1.1 net) PUD locations that are to be developed more than five years after first booking. These wells are a part of a development program which includes multiple wells from the same pad that has been pushed outside of the five year range due to our current strategy of drilling single well pads to hold acreage. We believe that this strategy allows for the wells to remain classified as PUD locations. A total of 6.3 Bcfe of estimate proved reserves are attributed to these wells.

Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2012, 2011 and 2010.


	2012
	Oil and NGLs (Bbls)			Natural Gas (Mcf)			Mcf Equivalents
Estimated Proved Reserves—Beginning of Period		15,316,001			274,292,315			366,188,321
Extensions, Discoveries and Additions		13,288,024			116,854,386			196,582,530
Revisions		12,740,217			(1,413,637	)		75,027,665
Improved Recovery		758,303			0			4,549,818
Purchases		43,176			0			259,056
Production		(1,090,115	)		(18,016,700	)		(24,557,390	)

Estimated Proved Reserves—End of Period		41,055,606			371,716,364			618,050,000


	2011
	Oil and NGLs (Bbls)			Natural Gas (Mcf)			Mcf Equivalents
Estimated Proved Reserves—Beginning of Period		12,342,828			127,621,835			201,678,803
Extensions, Discoveries and Additions		2,796,834			139,067,694			155,848,698
Revisions(a)		1,060,941			16,515,036			22,880,682
Production(b)		(884,602	)		(8,912,250	)		(14,219,862	)

Estimated Proved Reserves—End of Period		15,316,001			274,292,315			366,188,321


	2010
	Oil and NGLs (Bbls)			Natural Gas (Mcf)			Mcf Equivalents
Estimated Proved Reserves—Beginning of Period		11,509,983			56,163,170			125,223,068
Sale of Reserves in Place		(369,758	)		(12,251,612	)		(14,470,160	)
Extensions, Discoveries and Additions		3,461,768			93,229,532			114,000,140
Revisions		(1,542,033	)		(6,511,733	)		(15,763,931	)
Production(b)		(717,132	)		(3,007,522	)		(7,310,314	)

Estimated Proved Reserves—End of Period		12,342,828			127,621,835			201,678,803

(a)	Revisions includes 120.9 MBbls and 725.4 MMcfe related to our successful ASP pilot in the Illinois Basin.

(b)	Gas production excludes certain production associated with gas sales contracts for which we do not recognize reserves.


	Oil and NGLs (Bbls)		Natural Gas (Mcf)		Mcf Equivalent
Proved Developed Reserves
December 31, 2012		19,359,788		141,754,981		257,913,709
December 31, 2011		10,399,620		110,853,300		173,251,020
December 31, 2010		8,799,105		32,477,226		85,271,856

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from developmental drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs.

We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2012. Revisions due to price in our natural gas operations resulted in a significant loss of reserves. Prices used for natural gas reserves decreased from $4.55 in 2011 to $2.94 in 2012. Partially offsetting the decrease due to pricing were increased reserves due to additional field production data demonstrating better well performance than as of year-end 2011. We believe this increased performance is the result of improved completion techniques. During 2012, we executed an agreement to sell ethane as a separate product in our NGL stream, which is currently being utilized as plant fuel. As such, we booked for the first time ethane barrels as part of our NGL reserves. The ethane reserves contained within revisions to previous estimates are barrels associated to those wells which were considered to be proved locations as of December 31, 2011. We also had revisions in our non-operated properties. In our Westmoreland Marcellus, we saw reserve increases as a result of field production data demonstrating better well performance than last year’s estimates. For our Clearfield County Marcellus proved undeveloped acreage, we saw a reduction in proved reserves primarily due to offset well performance. In our Illinois Basin asset, we saw positive revisions, with a significant portion being the result of our re-frac program of stacked pay intervals instituted during the middle of 2012. We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2011. The majority of our positive revision of estimated proved reserves occurred in our Marcellus Shale properties, where our average per well estimated ultimate recovery (“EUR”) increased from 4.4 Bcfe to 5.3 Bcfe in our operated areas and from 3.0 Bcf to 4.2 Bcf in our non-operated Marcellus areas. These increases were due to additional field production data demonstrating better well performance compared to prior year performance. We believe that the increased performance was primarily the result of improved completion techniques. In total, the positive revisions in our Marcellus operations accounted for 84% of all revisions. Also impacting our revisions during 2011 was a change in the oil pricing from $76.03 per barrel in 2010 to $92.45 per barrel in 2011. We had significant revisions in our oil and NGL reserves of approximately 1.5 MMBOE for the year ended December 31, 2010, which were primarily due to a decrease in the pricing used for our NGLs from $57.65 per barrel in 2009 to $31.71 per barrel in 2010.

Extensions, discoveries and other additions. These are additions to estimated proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with estimated proved reserves or of new reservoirs of estimated proved reserves in old fields.

We had significant extensions, discoveries and other additions for the year ended December 31, 2012, of 13.3 MMBOE of oil and NGLs and 116.9 Bcf of natural gas. These additions were primarily due to the additional proved undeveloped locations that were added to our proved reserve estimates that were a result of our continued drilling success in the Marcellus Shale. A portion of the extension and discoveries were booked as a result of successful efforts from exploration wells drilled in the Utica Shale and the development of stacked reservoirs through the drilling of previously undeveloped acreage in the Illinois Basin. We had significant extensions, discoveries and other additions for the year ended December 31, 2011, of 2.8 MMBOE of oil and NGLs and 139.1 Bcf of natural gas. These additions were primarily due to the additional proved undeveloped locations that were added to our proved reserve estimates that were a result of our continued drilling success in the Marcellus Shale. A portion of the extension and discoveries were booked as a result of successful efforts from exploration wells drilled in the Burkett and Utica Shales. In the Illinois Basin, we successfully booked estimated proved reserves as a result of our ASP pilot, which were classified as revisions. For the year ended December 31, 2010 we had significant extensions, discoveries of 3.5 MMBOE for oil and NGLs and 93.2 Bcfe for natural gas. These additions were primarily due to the additional proved undeveloped locations that were added to our proved reserve estimates that were a result of our continued drilling success in the Marcellus Shale. Extensions, discoveries and other additions for the year ended December 31, 2009 of 0.9 MMBOE of oil and NGLs and 18.4 Bcfe of natural gas include increases in proved undeveloped locations as a result of our successful exploration efforts in the Marcellus Shale in conjunction with the change in the SEC’s rules to allow producers in continuous accumulation plays to report additional undrilled locations beyond one offset on each side of a horizontal producing well.

23. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of estimated proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2012, 2011 and 2010 ($ in thousands):


	2012			2011			2010
Future Cash Inflows	$	2,988,231	(a)	$	2,333,513	(b)	$	1,335,068	(c)
Future Costs:
Production		(1,387,653	)		(880,077	)		(542,814	)
Abandonment		(85,859	)		(65,560	)		(63,637	)
Development		(324,873	)		(251,821	)		(152,965	)

Net Future Cash Inflow Before Income Taxes		1,189,846			1,136,055			575,652
Future Income Tax Expense		(245,078	)		(277,568	)		(139,482	)

Total Future Net Cash Flows Before 10.0% Discount		944,768			858,487			436,170
Less: Effect of a 10.0% Discount Factor		(548,645	)		(444,552	)		(248,105	)

Standardized Measure of Discounted Future Net Cash Flows	$	396,123		$	413,935		$	188,065

(a)	Calculated using weighted average prices of $2.94 per Mcf, $90.92 per barrel of oil and $32.91 per barrel of NGLs

(b)	Calculated using weighted average prices of $4.55 per Mcf, $92.45 per barrel of oil and $46.34 per barrel of NGLs

(c)	Calculated using weighted average prices of $4.57 per Mcf, $76.03 per barrel of oil and $31.71 per barrel of NGLs

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:


	2012			2011			2010
Standardized Measure—Beginning of Period	$	413,935		$	188,065		$	144,379
Revisions of Previous Estimates:
Changes in Prices and Production Costs		(198,433	)		29,223			33,083
Revisions in Quantities		91,462			40,525			(36,541	)
Changes in Future Development Costs		(3,885	)		(19,539	)		(46,082	)
Accretion of Discount and Timing of Future Cash Flows		52,093			25,218			17,438
Net Change in Income Tax		27,405			(42,875	)		(34,117	)
Purchase (Sale) of Reserves in Place		1,188			0			(10,438	)
Plus Extensions, Discoveries, and Other Additions		88,749			159,047			44,135
Development Costs Incurred		57,149			61,290			24,825
Sales of Product—Net of Production Costs		(86,936	)		(78,763	)		(42,568	)
Changes in Timing and Other		(46,604	)		51,744			93,951

Standardized Measure—End of Period	$	396,123		$	413,935		$	188,065

24. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation):


	2012			2011			2010
Consolidated Entities (in thousands):
Revenues
Oil and Natural Gas Sales	$	134,574		$	111,879		$	67,224
Expenses
Production and Lease Operating Expense		47,638			33,116			24,656
Impairment Expense		20,505			14,316			8,424
Exploration Expense		4,782			2,507			2,578
Depletion, Depreciation, Amortization and Accretion		44,955			27,670			21,422

Total Costs		117,880			77,609			57,080
Pre-Tax Operating Income (Loss)		16,694			34,270			10,144
Income Tax Expense(a)		6,778			10,760			4,118

Results of Operations for Oil and Gas Producing Activities	$	9,916		$	23,510		$	6,026

Share of Equity Method Investments (in thousands):
Expenses
Depletion, Depreciation, Amortization and Accretion	$	1,082		$	1,568		$	181

Total Costs		1,082			1,568			181
Pre-Tax Operating Loss		(1,082	)		(1,568	)		(181	)
Income Tax Benefit(a)		435			519			75

Results of Operations for Oil and Gas Producing Activities	$	(647	)	$	(1,049	)	$	(106	)

Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities	$	9,269		$	22,461		$	5,920

(a)	Computed using the effective rate for continuing operations for each period: 40.6% in 2012; 31.4% in 2011 and; 40.6% in 2010.

25. LITIGATION

Illinois Basin EPA Consent Decree

In September 2006, the United States Department of Justice (“DOJ”), the United States Environmental Protection Agency (“EPA”) and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) in the course of our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, we entered a consent decree to resolve the enforcement. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. The consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.

In January 2010, we submitted certain proposed revisions to a Directed Inspection and Maintenance Plan previously implemented by us pursuant to the terms of the consent decree. In general, the proposed revisions update the plan to reflect changes in hydrogen sulfide control measures and procedures implemented in the field and changes in procedures for responding to resident complaints of hydrogen sulfide odors. The EPA, DOJ and Illinois EPA all approved these revisions.

Settlement Agreement—Illinois Class Action Litigation

We were a defendant in a class action lawsuit filed in the United States District Court for the Southern District of Illinois. This action was commenced in October 2006 by plaintiffs Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport and Petrolia, Illinois. The complaint asserted several causes of action, including violation of the Resource Conservation and Recovery Act, Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct.

In December 2009, we entered into a Settlement Agreement and Release (the “Settlement Agreement”) with Leib and Thompson, individually and on behalf of a certified class, to settle the class action lawsuit. Under the terms of the Settlement Agreement, without any admission of liability, we agreed to pay the class a total of $1.9 million. Pursuant to the terms of a pollution liability policy, $1.0 million of the settlement payment was funded by our insurance carrier. Pursuant to the Settlement Agreement, we also agreed to permanently plug four inactive oil wells. In return for the above consideration, each member of the class released all claims against us that in any way related to hydrogen sulfide or other environmental conditions in the class area that were the subject of, or could have been the subject of, the claims alleged in the class action lawsuit. In addition, each class member released any claims related to any future releases of hydrogen sulfide in the class area on the condition that we substantially comply with the terms and conditions of the consent decree describe above in “Illinois Basin EPA Consent Decree” . The Settlement Agreement did not provide for a release of any potential individual claims of other class members since those claims were not the subject of the class action lawsuit. The Settlement Agreement became effective in April 2010.

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

In July 2009, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Westmoreland County, Pennsylvania (the “Snyder Case”). The named plaintiffs were five individuals

who sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Snyder Case generally asserted that a binding contract to lease oil and gas property was formed between the Company and each proposed class member when representatives of Duncan Land & Energy, Inc. (“Duncan Land”), a leasing agent that we engaged, presented a form of proposed oil and gas lease to each person, and each person signed the proposed oil and gas lease form and delivered the executed proposed lease to representatives of Duncan Land. 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, together with interest, costs, expenses and attorneys’ fees.

In May 2011, we entered into a Settlement Agreement with respect to these legal proceedings. In July 2011, the court approved the Settlement Agreement, pursuant to which we offered each eligible class member an oil and gas lease, in a form agreed to by the parties, with a prepaid rental of $2,500 per acre for a five-year term with a 15% royalty. We also agreed to pay $30,000 to plaintiffs’ attorneys for the anticipated expenses of administration of the Settlement Agreement. Additionally, we deposited $2.5 million into a fund for distribution to class members and for attorney’s fees, costs and expenses of counsel for the class. The final order regarding the Settlement Agreement dismissed all claims against us with prejudice and without any admission of liability, and provided a release by all class members of all claims against us in connection with the litigation.

In June 2009, we were also named as a defendant in a lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Liegey Case”). The Liegey Case was brought by eight individuals involving oil and gas leasing activity in Clearfield County, Pennsylvania. The complaint in the Liegey Case asserted similar claims and requests for relief as those made in the Snyder Case described above. In June 2010, we settled the case and in July 2010, the court dismissed the case.

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 have 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 and an order for payment 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 seek 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 trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal and the parties filed briefs and responses during the second half of 2012. The appeal was argued by the parties in February 2013; however, as of the date of this report, there has been no ruling on the appeal.

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 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.

26. SUBSEQUENT EVENTS

Senior Notes due 2020

On April 26, 2013, we issued $100.0 million in aggregate principal amount of Senior Notes due 2020 in a private offering as additional notes to the $250.0 million aggregate principal amount of 8.875% senior notes due 2020 (“the Additional Notes”) that we sold in a private offering on December 12, 2012 (see Note 11,Long-Term Debt, to our Consolidated Financial Statements). The Additional Notes were issued at an issue price of 105% of par plus accrued interest from December 12, 2012. Net proceeds after discounts and offering expenses were approximately $102.8 million, plus accrued interest. In connection with this issuance, we gave notice to the administrative agent under our Senior Credit Facility of our election to reduce the maximum commitments of the lenders under our Senior Credit Facility to $215.0 million.

DJ Basin

During the first quarter of 2013, we entered and agreement to sell our remaining DJ Basin assets for $3.1 million. This transaction closed during the second quarter of 2013 and resulted in a gain of approximately $1.0 million. We have no continuing activities in the DJ Basin or continuing cash flows from this region.

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

On May 3, 2013, the Superior Court reversed the decision of the Common Pleas Court, which in 2012 had dismissed the Cardinale Case with prejudice, and remanded the case for further proceedings. At this time, the Billotte case and the Meeker case remained stayed. To date, we have not been served with a complaint in the Meeker case, but we still expect that the claims mirror those set forth in the Cardinale and Billotte cases. We expect to make a determination as to the consolidation of these cases with the Cardinale case within the next three to six months as the Cardinale case proceeds.

We expect to enter into a case management plan with the Cardinale plaintiffs’ counsel within the next several months, which will outline the timing for class discovery, class certification, trial discovery and the trial. In the meantime, we are preparing for class discovery. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses.

27. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

($ and Shares in Thousands Except per Share Data)


	2012
	March			June			September			December
Revenues	$	33,834		$	30,257		$	38,929		$	45,119
Costs and Expenses		30,006			(25,936	)		40,671			46,157

Net Income (Loss) From Continuing Operations		3,828			56,193			(1,742	)		(1,038	)
Net Loss From Discontinued Operations		(5,355	)		(3,050	)		(258	)		(2,280	)

Net Income (Loss)		(1,527	)		53,143			(2,000	)		(3,318	)
Net Income Attributable to Noncontrolling Interests		101			222			193			303

Net Income (Loss) Attributable to Rex Energy	$	(1,628	)	$	52,921		$	(2,193	)	$	(3,621	)

Income (Loss) per Common Share Attributable to Rex Common Shareholders:
Basic—Continuing Operations Attributable to Rex Energy	$	0.08		$	1.08		$	(0.04	)	$	(0.03	)
Basic—Discontinued Operations		(0.11	)		(0.06	)		0.00			(0.04	)

Basic—Net Income (Loss)	$	(0.03	)	$	1.02		$	(0.04	)	$	(0.07	)

Basic—Weighted Average Shares Outstanding		48,744			52,009			52,036			52,278
Diluted—Continuing Operations Attributable to Rex Energy	$	0.08		$	1.06		$	(0.04	)	$	(0.03	)
Diluted—Discontinued Operations		(0.11	)		(0.06	)		0.00			(0.04	)

Diluted—Net Income (Loss)	$	(0.03	)	$	1.00		$	(0.04	)	$	(0.07	)

Diluted—Weighted Average Shares Outstanding		49,693			52,876			52,036			52,278


	2011
	March			June			September			December
Revenues	$	23,147		$	29,023		$	30,755		$	31,681
Costs and Expenses		26,680			21,226			18,089			30,532

Net Income (Loss) From Continuing Operations		(3,533	)		7,797			12,666			1,149
Net Loss From Discontinued Operations		(4,069	)		(4,313	)		(20,812	)		(4,263	)

Net Income (Loss)		(7,602	)		3,484			(8,146	)		(3,114	)
Net Income (Loss) Attributable to Noncontrolling Interests		(102	)		44			44			7

Net Income (Loss) Attributable to Rex Energy	$	(7,500	)	$	3,440		$	(8,190	)	$	(3,121	)

Income (Loss) per Common Share Attributable to Rex Common Shareholders:
Basic—Continuing Operations Attributable to Rex Energy	$	(0.08	)	$	0.18		$	0.29		$	0.03
Basic—Discontinued Operations		(0.09	)		(0.10	)		(0.47	)		(0.10	)

Basic—Net Income (Loss)	$	(0.17	)	$	0.08		$	(0.18	)	$	(0.07	)

Basic—Weighted Average Shares Outstanding		43,862			43,880			43,951			44,026
Diluted—Continuing Operations Attributable to Rex Energy	$	(0.08	)	$	0.18		$	0.29		$	0.03
Diluted—Discontinued Operations		(0.09	)		(0.10	)		(0.47	)		(0.10	)

Diluted—Net Income (Loss)	$	(0.17	)	$	0.08		$	(0.18	)	$	(0.07	)

Diluted—Weighted Average Shares Outstanding		43,862			44,451			44,384			44,567

28. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of December 31, 2012, we had outstanding $250.0 million of Senior Notes due 2020, as shown in Note 11,Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of December 31, 2012;

•

Rex Energy I, LLC

•

Rex Energy Operating Corporation

•

Rex Energy IV, LLC

•

PennTex Resources Illinois, Inc.

•

R.E. Gas Development, LLC

The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions Holdings and its subsidiaries, R.E. Disposal, LLC (formerly known as NorthStar #3, LLC) and Rex Energy Rockies, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of December 31, 2012, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of December 31, 2012 and 2011, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2012.

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

FOR THE YEAR ENDED DECEMBER 31, 2012

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


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	4,227		$	824		$	38,924		$	0		$	43,975
Accounts Receivable		26,490			3,367			0			(4,877	)		24,980
Taxes Receivable		0			0			6,429			0			6,429
Short-Term Derivative Instruments		12,005			0			0			0			12,005
Assets Held For Sale		0			2,279			0			0			2,279
Inventory, Prepaid Expenses and Other		1,277			13			26			0			1,316

Total Current Assets		43,999			6,483			45,379			(4,877	)		90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		486,706			0			0			(1,258	)		485,448
Unevaluated Oil and Gas Properties		161,618			0			0			0			161,618
Other Property and Equipment		45,613			4,455			0			5			50,073
Wells and Facilities in Progress		92,089			4,780			0			(71	)		96,798
Pipelines		6,116			0			0			0			6,116

Total Property and Equipment		792,142			9,235			0			(1,324	)		800,053
Less: Accumulated Depreciation, Depletion and Amortization		(145,514	)		(674	)		0			150			(146,038	)

Net Property and Equipment		646,628			8,561			0			(1,174	)		654,015
Deferred Financing Costs and Other Assets—Net		2,427			199			7,403			0			10,029
Equity Method Investments		16,978			0			0			0			16,978
Intercompany Receivables		3,795			0			440,269			(444,064	)		0
Investment in Subsidiaries—Net		(227	)		(232	)		193,790			(193,331	)		0
Long-Term Derivative Instruments		704			0			0			0			704

Total Assets	$	714,304		$	15,011		$	686,841		$	(643,646	)	$	772,710

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	29,818		$	1,560		$	0		$	(244	)	$	31,134
Accrued Expenses		19,891			1,036			1,494			0			22,421
Short-Term Derivative Instruments		1,389			0			0			0			1,389
Current Deferred Tax Liability		0			0			539			0			539
Liabilities Related to Assets Held For Sale		0			52			0			0			52

Total Current Liabilities		51,098			2,648			2,033			(244	)		55,535
8.875% Senior Notes Due 2020		0			0			250,000			0			250,000
Discount on Senior Notes		0			0			(1,742	)		0			(1,742	)
Senior Secured Line of Credit and Long-Term Debt		26			5,598			0			(4,633	)		991
Long-Term Derivative Instruments		1,510			0			0			0			1,510
Long-Term Deferred Tax Liability		0			0			23,625			0			23,625
Other Deposits and Liabilities		5,675			0			0			0			5,675
Future Abandonment Cost		24,822			0			0			0			24,822
Intercompany Payables		367,704			76,360			0			(444,064	)		0

Total Liabilities		450,835			84,606			273,916			(448,941	)		360,416
Stockholders’ Equity
Common Stock, $0.001 par value per share, 100,000,000 shares authorized and 53,213,264 shares issued and outstanding on December 31, 2012		0			0			52			0			52
Additional Paid-In Capital		177,143			(407	)		451,062			(176,736	)		451,062
Accumulated Earnings (Deficit)		86,326			(69,148	)		(38,189	)		(18,588	)		(39,595	)

Rex Energy Stockholders’ Equity		263,469			(69,551	)		412,925			(195,324	)		411,519
Noncontrolling Interests		0			(44	)		0			819			775

Total Stockholders’ Equity		263,469			(69,595	)		412,925			(194,505	)		412,294

Total Liabilities and Stockholders’ Equity	$	714,304		$	15,011		$	686,841		$	(643,446	)	$	772,710

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2012

($ in Thousands)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	134,574		$	0		$	0		$	0		$	134,574
Field Services Revenue		0			15,637			0			(2,234	)		13,403
Other Revenue		218			0			0			(56	)		162

TOTAL OPERATING REVENUE		134,792			15,637			0			(2,290	)		148,139
OPERATING EXPENSES
Production and Lease Operating Expense		47,618			20			0			0			47,638
General and Administrative Expense		19,283			1,007			3,159			(104	)		23,345
Loss on Disposal of Asset		50			8			0			0			58
Impairment Expense		20,505			80			0			0			20,585
Exploration Expense		4,782			0			0			0			4,782
Depreciation, Depletion, Amortization and Accretion		44,993			527			0			(83	)		45,437
Field Services Operating Expense		0			9,859			0			(1,619	)		8,240
Other Operating Expense		1,136			0			0			0			1,136

TOTAL OPERATING EXPENSES		138,367			11,501			3,159			(1,806	)		151,221
INCOME (LOSS) FROM OPERATIONS		(3,575	)		4,136			(3,159	)		(484	)		(3,082	)
OTHER INCOME (EXPENSE)
Interest Expense		(55	)		(26	)		(6,362	)		0			(6,443	)
Gain on Derivatives, Net		10,687			0			0			0			10,687
Other Income (Expense)		99,575			0			(922	)		(104	)		98,549
Loss From Equity Method Investments		(3,921	)		0			0			0			(3,921	)
Income (Loss) From Equity in Consolidated Subsidiaries		(68	)		68			51,363			(51,363	)		0

TOTAL OTHER INCOME (LOSS)		106,218			42			44,079			(51,467	)		98,872
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		102,643			4,178			40,920			(51,951	)		95,790
Income Tax (Expense) Benefit		(41,772	)		(1,336	)		4,559			0			(38,549	)

INCOME (LOSS) FROM CONTINUING OPERATIONS		60,871			2,842			45,479			(51,951	)		57,241
Loss From Discontinued Operations, Net of Income Taxes		0			(10,943	)		0			0			(10,943	)

NET INCOME (LOSS)		60,871			(8,101	)		45,479			(51,951	)		46,298
Net Income Attributable to Noncontrolling Interests		0			819			0			0			819

NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	60,871		$	(8,920	)	$	45,479		$	(51,951	)	$	45,479

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE YEAR ENDING DECEMBER 31, 2012

($ in Thousands)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	60,871		$	(8,101	)	$	45,479		$	(51,951	)	$	46,298
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		3,921			0			0			0			3,921
Non-Cash Expenses		33			14			3,144			0			3,191
Depreciation, Depletion, Amortization and Accretion		44,993			527			1,004			(83	)		46,441
Deferred Income Tax Expense (Benefit)		35,376			(7,152	)		(4,559	)		0			23,665
Unrealized Loss on Derivatives		5,532			0			0			0			5,532
Dry Hole Expense		320			336			0			0			656
(Gain) Loss on Sale of Assets and Equity Method Investments		(99,355	)		(2,118	)		922			0			(100,551	)
Impairment Expense		20,505			19,850			0			0			40,355
Changes in operating assets and liabilities
Accounts Receivable		29,564			(3,736	)		(39,325	)		(201	)		(13,698	)
Inventory, Prepaid Expenses and Other Assets		(139	)		32			15			0			(92	)
Accounts Payable and Accrued Expenses		(6,813	)		(766	)		916			(107	)		(6,770	)
Other Assets and Liabilities		(3,208	)		(64	)		0			29			(3,243	)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		91,600			(1,178	)		7,596			(52,313	)		45,705
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		2,915			(1,931	)		(56,489	)		51,643			0
Proceeds from Joint Venture Leasing Initiatives		260			0			0			0			260
Contributions to Equity Method Investments		0			(4,087	)		0			0			(4,087	)
Proceeds from the Sale of Assets and Equity Method Investments		128,554			4,871			0			0			133,425
Acquisitions of Undeveloped Acreage		(51,783	)		(19	)		0			0			(51,802	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(177,892	)		(1,316	)		0			670			(178,538	)

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(97,946	)		1,380			(56,489	)		52,313			(100,742	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			730			126,000			0			126,730
Repayments of Long-Term Debt and Lines of Credit		0			0			(351,000	)		0			(351,000	)
Repayments of Loans and Other Notes Payable		(764	)		(198	)		0			0			(962	)
Proceeds from 8.875% Senior Notes, net of Discount		0			0			248,250			0			248,250
Debt Issuance Costs		0			0			(6,397	)		0			(6,397	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		0			0			(234	)		0			(234	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			0			70,583			0			70,583
Proceeds from the Exercise of Stock Options		0			0			565			0			565
Capital Distributions by the Partners of Consolidated Joint Ventures		0			(319	)		0			0			(319	)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(764	)		213			87,767			0			87,216
NET INCREASE (DECREASE) IN CASH		(7,110	)		415			38,874			0			32,179
CASH – BEGINNING		11,337			409			50			0			11,796

CASH – ENDING	$	4,227		$	824		$	38,924		$	0		$	43,975

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

FOR THE YEAR ENDED DECEMBER 31, 2011

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


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	11,337		$	409		$	50		$	0		$	11,796
Accounts Receivable		21,912			877			0			(5,072	)		17,717
Short-Term Derivative Instruments		10,404			0			0			0			10,404
Assets Held For Sale		0			24,808			0			0			24,808
Inventory, Prepaid Expenses and Other		1,139			11			41			0			1,191

Total Current Assets		44,792			26,105			91			(5,072	)		65,916
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		350,554			0			0			(616	)		349,938
Unevaluated Oil and Gas Properties		123,241			0			0			0			123,241
Other Property and Equipment		42,086			1,456			0			0			43,542
Wells and Facilities in Progress		61,397			5,193			0			(42	)		66,548
Pipelines		4,408			0			0			0			4,408

Total Property and Equipment		581,686			6,649			0			(658	)		587,677
Less: Accumulated Depreciation, Depletion and Amortization		(107,296	)		(204	)		0			67			(107,433	)

Net Property and Equipment		474,390			6,445			0			(591	)		480,244
Deferred Financing Costs and Other Assets—Net		253			192			2,960			0			3,405
Equity Method Investments		41,683			0			0			0			41,683
Long-Term Deferred Tax Asset		0			0			1,727			0			1,727
Intercompany Receivables		6,626			0			407,370			(413,996	)		0
Investment in Subsidiaries – Net		(151	)		1,860			107,450			(109,159	)		0
Long-Term Derivative Instruments		8,576			0			0			0			8,576

Total Assets	$	576,169		$	34,602		$	519,598		$	(528,818	)	$	601,551

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	41,118		$	616		$	0		$	(176	)	$	41,558
Accrued Expenses		14,967			596			119			0			15,682
Short-Term Derivative Instruments		2,363			0			0			0			2,363
Current Deferred Tax Liability		0			0			2,141			0			2,141
Liabilities Related to Assets Held For Sale		0			1,622			0			0			1,622

Total Current Liabilities		58,448			2,834			2,260			(176	)		63,366
Senior Secured Line of Credit and Long-Term Debt		0			5,034			225,000			(4,896	)		225,138
Long-Term Derivative Instruments		1,275			0			0			0			1,275
Long-Term Deferred Tax Liability		0			0			84			0			84
Other Deposits and Liabilities		744			0			0			0			744
Future Abandonment Cost		18,670			0			0			0			18,670
Intercompany Payables		336,395			77,601			0			(413,996	)		0

Total Liabilities		411,532			85,469			227,344			(419,068	)		309,277
Stockholders’ Equity
Common Stock, $0.001 par value per share, 100,000,000 shares authorized and 44,859,220 shares issued and outstanding on December 31, 2011		0			0			44			0			44
Additional Paid-In Capital		177,143			3,256			376,843			(180,399	)		376,843
Accumulated Earnings (Deficit)		(16,506	)		(54,405	)		(84,633	)		70,656			(84,888	)

Rex Energy Stockholders’ Equity		160,637			(51,149	)		292,254			(109,743	)		291,999
Noncontrolling Interests		0			282			0			(7	)		275

Total Stockholders’ Equity		160,637			(50,867	)		292,254			(109,750	)		292,274
Total Liabilities and Stockholders’ Equity	$	576,169		$	34,602		$	519,598		$	(528,818	)	$	601,551

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2011

($ in Thousands)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	111,879		$	0		$	0		$	0		$	111,879
Field Services Revenue		0			3,546			0			(1,028	)		2,518
Other Revenue		209			0			0			0			209

TOTAL OPERATING REVENUE		112,088			3,546			0			(1,028	)		114,606
OPERATING EXPENSES
Production and Lease Operating Expense		33,106			10			0			0			33,116
General and Administrative Expense		21,424			586			1,662			(36	)		23,636
Loss on Disposal of Asset		353			149			0			0			502
Impairment Expense		14,316			315			0			0			14,631
Exploration Expense		2,507			0			0			0			2,507
Depreciation, Depletion, Amortization and Accretion		27,672			231			0			(47	)		27,856
Field Services Operating Expense		0			2,470			0			(720	)		1,750
Other Operating Expense		819			0			0			0			819

TOTAL OPERATING EXPENSES		100,197			3,761			1,662			(803	)		104,817
INCOME (LOSS) FROM OPERATIONS		11,891			(215	)		(1,662	)		(225	)		9,789
OTHER INCOME (EXPENSE)
Interest Expense		(107	)		(2	)		(2,405	)		0			(2,514	)
Gain on Derivatives, Net		18,916			0			0			0			18,916
Other Income (Expense)		13			101			0			(35	)		79
Income From Equity Method Investments		81			0			0			0			81
Income (Loss) From Equity in Consolidated Subsidiaries		(53	)		53			(12,925	)		12,925			0

TOTAL OTHER INCOME (LOSS)		18,850			152			(15,330	)		12,890			16,562
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		30,741			(63	)		(16,992	)		12,665			26,351
Income Tax (Expense) Benefit		(9,927	)		33			1,624			0			(8,270	)

INCOME (LOSS) FROM CONTINUING OPERATIONS		20,814			(30	)		(15,368	)		12,665			18,081
Loss From Discontinued Operations, Net of Income Taxes		0			(33,457	)		0			0			(33,457	)

NET INCOME (LOSS)		20,814			(33,487	)		(15,368	)		12,665			(15,376	)
Net Loss Attributable to Noncontrolling Interests		0			(7	)		0			0			(7	)

NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	20,814		$	(33,480	)	$	(15,368	)	$	12,665		$	(15,369	)

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE YEAR ENDING DECEMBER 31, 2011

($ in Thousands)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	20,814		$	(33,487	)	$	(15,368	)	$	12,665		$	(15,376	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Gain From Equity Method Investments		(81	)		0			0			0			(81	)
Non-Cash Expenses		118			2			1,625			0			1,745
Depreciation, Depletion, Amortization and Accretion		27,672			316			505			(47	)		28,446
Deferred Income Tax Expense (Benefit)		(10,234	)		1,271			1,624			0			(7,339	)
Unrealized Gain on Derivatives		(12,704	)		0			0			0			(12,704	)
Dry Hole Expense		6			32,763			0			0			32,769
Loss on Sale of Assets and Equity Method Investments		353			149			0			0			502
Impairment Expense		14,316			13,492			0			0			27,808
Changes in operating assets and liabilities
Accounts Receivable		188,899			29,099			(211,952	)		5,072			11,118
Inventory, Prepaid Expenses and Other Assets		157			(56	)		(15	)		0			86
Accounts Payable and Accrued Expenses		1,727			(3,124	)		405			(136	)		(1,128	)
Other Assets and Liabilities		(2,341	)		961			0			41			(1,339	)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		228,702			41,386			(223,176	)		17,595			64,507
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(2,337	)		10,811			9,121			(17,595	)		0
Proceeds from Joint Venture Leasing Initiatives		3,209			0			0			0			3,209
Change in Restricted Cash		16,086			0			0			0			16,086
Contributions to Equity Method Investments		0			(23,204	)		0			0			(23,204	)
Proceeds from the Sale of Assets and Equity Method Investments		2,293			436			0			0			2,729
Acquisitions of Undeveloped Acreage		(76,698	)		(1,871	)		0			0			(78,569	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(169,689	)		(27,444	)		308			0			(196,825	)

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(227,136	)		(41,272	)		9,429			(17,595	)		(276,574	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			0			240,000			0			240,000
Repayments of Long-Term Debt and Lines of Credit		0			0			(25,000	)		0			(25,000	)
Repayments of Loans and Other Notes Payable		(831	)		(48	)		0			0			(879	)
Debt Issuance Costs		0			0			(2,615	)		0			(2,615	)
Proceeds from the Exercise of Stock Options		0			0			1,362			0			1,362
Capital Distributions by the Partners of Consolidated Joint Ventures		0			(20	)		0			0			(20	)
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures		7			0			0			0			7

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(824	)		(68	)		213,747			0			212,855
NET INCREASE IN CASH		742			46			0			0			788
CASH – BEGINNING		10,595			363			50			0			11,008

CASH – ENDING	$	11,337		$	409		$	50		$	0		$	11,796

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2010

($ in Thousands)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	67,224		$	0		$	0		$	0		$	67,224
Field Services Revenue		0			1,718			0			(352	)		1,366
Other Revenue		173			116			0			(116	)		173

TOTAL OPERATING REVENUE		67,397			1,834			0			(468	)		68,763
OPERATING EXPENSES
Production and Lease Operating Expense		24,764			10			0			(118	)		24,656
General and Administrative Expense		15,819			461			949			(88	)		17,141
Gain on Disposal of Asset		(16,395	)		0			0			0			(16,395	)
Impairment Expense		8,424			439			0			0			8,863
Exploration Expense		2,578			0			0			0			2,578
Depreciation, Depletion, Amortization and Accretion		21,265			323			0			(20	)		21,568
Field Services Operating Expense		0			1,188			0			0			1,188
Other Operating Expense (Income)		(42	)		195			0			0			153

TOTAL OPERATING EXPENSES		56,413			2,616			949			(226	)		59,752
INCOME (LOSS) FROM OPERATIONS		10,984			(782	)		(949	)		(242	)		9,011
OTHER INCOME (EXPENSE)
Interest Income (Expense)		(181	)		12			(1,071	)		0			(1,240	)
Gain on Derivatives, Net		6,055			0			0			0			6,055
Other Expense		(233	)		0			0			(88	)		(321	)
Loss From Equity Method Investments		(200	)		0			0			0			(200	)
Income (Loss) From Equity in Consolidated Subsidiaries		(115	)		115			6,976			(6,976	)		0

TOTAL OTHER INCOME (LOSS)		5,326			127			5,905			(7,064	)		4,294
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		16,310			(655	)		4,956			(7,306	)		13,305
Income Tax (Expense) Benefit		(6,791	)		210			1,081			0			(5,500	)

INCOME (LOSS) FROM CONTINUING OPERATIONS		9,519			(445	)		6,037			(7,306	)		7,805
Loss From Discontinued Operations, Net of Income Taxes		0			(2,022	)		0			0			(2,022	)

NET INCOME (LOSS)		9,519			(2,467	)		6,037			(7,306	)		5,783
Net Loss Attributable to Noncontrolling Interests		0			(253	)		0			0			(253	)

NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	9,519		$	(2,214	)	$	6,037		$	(7,306	)	$	6,036

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE YEAR ENDING DECEMBER 31, 2010

($ in Thousands)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	9,519		$	(2,467	)	$	6,037		$	(7,306	)	$	5,783
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		200			0			0			0			200
Non-Cash Expenses		222			115			914			0			1,251
Depreciation, Depletion, Amortization and Accretion		21,265			323			238			(20	)		21,806
Deferred Income Tax Expense (Benefit)		6,487			(1,635	)		(1,081	)		0			3,771
Unrealized Gain on Derivatives		(5,960	)		0			0			0			(5,960	)
Dry Hole Expense		3			0			0			0			3
Gain on Sale of Assets and Equity Method Investments		(16,395	)		0			0			0			(16,395	)
Impairment Expense		8,424			439			0			0			8,863
Changes in operating assets and liabilities
Accounts Receivable		2,456			46,683			(63,598	)		(68	)		(14,527	)
Inventory, Prepaid Expenses and Other Assets		(210	)		(6	)		0			0			(216	)
Accounts Payable and Accrued Expenses		28,768			3,614			(59	)		0			32,323
Other Assets and Liabilities		(1,483	)		(1,317	)		0			0			(2,800	)

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		53,296			45,749			(57,549	)		(7,394	)		34,102
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(13,885	)		15,952			(9,111	)		7,044			0
Proceeds from Joint Venture Leasing Initiatives		6,352			0			0			0			6,352
Change in Restricted Cash		(16,086	)		0			0			0			(16,086	)
Contributions to Equity Method Investments		0			(14,018	)		0			0			(14,018	)
Proceeds from the Sale of Assets and Equity Method Investments		79,229			0			0			0			79,229
Acquisitions of Undeveloped Acreage		(44,925	)		(27,460	)		0			0			(72,385	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(58,220	)		(20,143	)		0			350			(78,013	)

NET CASH USED IN INVESTING ACTIVITIES		(47,535	)		(45,669	)		(9,111	)		7,394			(94,921	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			0			85,000			0			85,000
Repayments of Long-Term Debt and Lines of Credit		0			0			(98,000	)		0			(98,000	)
Repayments of Loans and Other Notes Payable		(751	)		(2	)		0			0			(753	)
Debt Issuance Costs		0			0			(701	)		0			(701	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			0			80,192			0			80,192
Proceeds from the Exercise of Stock Options		0			0			220			0			220
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures		0			287			0			0			287

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(751	)		285			66,711			0			66,245
NET INCREASE IN CASH		5,010			365			51			0			5,426
CASH – BEGINNING		5,582			0			0			0			5,582

CASH – ENDING	$	10,592		$	365		$	51		$	0		$	11,008

Rex Energy Inactive 8-KIndex to Financial Statements