Exhibit 99.1

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Share Data)

	March  31, 2013 (unaudited)			December 31, 2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	11,640		$	43,975
Accounts Receivable		29,102			24,980
Taxes Receivable		6,396			6,429
Short-Term Derivative Instruments		4,742			12,005
Assets Held for Sale		2,138			2,279
Inventory, Prepaid Expenses and Other		1,301			1,316
Total Current Assets		55,319			90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		537,638			485,448
Unevaluated Oil and Gas Properties		171,901			165,503
Other Property and Equipment		54,317			50,073
Wells and Facilities in Progress		107,214			92,913
Pipelines		6,125			6,116
Total Property and Equipment		877,195			800,053
Less: Accumulated Depreciation, Depletion and Amortization		(156,390	)		(146,038	)
Net Property and Equipment		720,805			654,015
Deferred Financing Costs and Other Assets—Net		10,380			10,029
Equity Method Investments		16,800			16,978
Long-Term Derivative Instruments		150			704
Total Assets	$	803,454		$	772,710
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	44,272		$	31,134
Accrued Expenses		37,656			22,421
Short-Term Derivative Instruments		5,072			1,389
Current Deferred Tax Liability		565			539
Liabilities Related to Assets Held for Sale		50			52
Total Current Liabilities		87,615			55,535
8.875% Senior Notes Due 2020		250,000			250,000
Discount on Senior Notes		(1,704	)		(1,742	)
Senior Secured Line of Credit and Long-Term Debt		1,167			991
Long-Term Derivative Instruments		2,221			1,510
Long-Term Deferred Tax Liability		21,491			23,625
Other Deposits and Liabilities		5,739			5,675
Future Abandonment Cost		25,671			24,822
Total Liabilities	$	392,200		$	360,416
Commitments and Contingencies (See Note 13)
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 53,227,718 shares issued and outstanding on March 31, 2013 and 53,213,264 shares issued and outstanding on December 31, 2012.		52			52
Additional Paid-In Capital		452,432			451,062
Accumulated Deficit		(42,429	)		(39,595	)
Rex Energy Stockholders’ Equity		410,055			411,519
Noncontrolling Interests		1,199			775
Total Stockholders’ Equity		411,254			412,294
Total Liabilities and Stockholders’ Equity	$	803,454		$	772,710

See accompanying notes to the unaudited consolidated financial statements

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in Thousands, Except per Share Data)

	For the Three Months Ended March 31,
	2013			2012
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	40,940		$	31,483
Field Services Revenue		6,506			2,306
Other Revenue		24			45
TOTAL OPERATING REVENUE		47,470			33,834
OPERATING EXPENSES
Production and Lease Operating Expense		13,400			12,299
General and Administrative Expense		7,796			5,411
(Gain) Loss on Disposal of Asset		(10	)		26
Impairment Expense		66			2,793
Exploration Expense		2,044			1,092
Depreciation, Depletion, Amortization and Accretion		11,157			9,544
Field Service Operating Expense		4,055			1,456
Other Operating Expense		444			326
TOTAL OPERATING EXPENSES		38,952			32,947
INCOME FROM OPERATIONS		8,518			887
OTHER INCOME (EXPENSE)
Interest Expense		(4,005	)		(1,739	)
Gain (Loss) on Derivatives, Net		(8,540	)		7,439
Other Income (Expense)		(139	)		6
Loss on Equity Method Investments		(178	)		(134	)
TOTAL OTHER INCOME (EXPENSE)		(12,862	)		5,572
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(4,344	)		6,459
Income Tax Benefit (Expense)		2,004			(2,631	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		(2,340	)		3,828
Loss From Discontinued Operations, Net of Income Taxes		(61	)		(5,355	)
NET LOSS		(2,401	)		(1,527	)
Net Income Attributable to Noncontrolling Interests		433			101
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(2,834	)	$	(1,628	)
Earnings (loss) per common share:
Basic—Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders	$	(0.05	)	$	0.08
Basic—Net Loss From Discontinued Operations Attributable to Rex Common Shareholders		0.00			(0.11	)
Basic—Net Loss Attributable to Rex Common Shareholders	$	(0.05	)	$	(0.03	)
Basic—Weighted Average Shares of Common Stock Outstanding		52,367			48,744
Diluted—Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders	$	(0.05	)	$	0.08
Diluted—Net Loss From Discontinued Operations Attributable to Rex Common Shareholders		0.00			(0.11	)
Diluted—Net Loss Attributable to Rex Common Shareholders	$	(0.05	)	$	(0.03	)
Diluted—Weighted Average Shares of Common Stock Outstanding		52,367			49,693

See accompanying notes to the unaudited consolidated financial statements

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REX ENERGY CORPORATION

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

FOR THE THREE-MONTH PERIOD ENDED MARCH 31, 2013

(Unaudited, in Thousands)

	Common Stock					Additional Paid-In Capital		Accumulated Deficit			Rex Energy Stockholders’ Equity
	Shares			Par Value										Noncontrolling Interests			Total Stockholders’ Equity
BALANCE December 31, 2012		53,213		$	52	$	451,062	$	(39,595	)	$	411,519		$	775		$	412,294
Non-Cash Compensation		0			0		1,204		0			1,204			0			1,204
Stock Option Exercises		17			0		166		0			166			0			166
Issuance of Restricted Stock, Net of Forfeitures		(2	)		0		0		0			0			0			0
Capital Distributions		0			0		0		0			0			(9	)		(9	)
Net Income (Loss)		0			0		0		(2,834	)		(2,834	)		433			(2,401	)
BALANCE March 31, 2013		53,228		$	52	$	452,432	$	(42,429	)	$	410,055		$	1,199		$	411,254

See accompanying notes to the unaudited consolidated financial statements

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(2,401	)	$	(1,527	)
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		178			134
Non-cash Expenses		1,610			474
Depreciation, Depletion, Amortization and Accretion		11,157			9,802
Unrealized (Gain) Loss on Derivatives		12,211			(3,654	)
Dry Hole Expense		0			503
Deferred Income Tax Benefit		(2,108	)		(1,108	)
Impairment Expense		66			11,063
(Gain) Loss on Sale of Asset		(6	)		170
Changes in operating assets and liabilities
Accounts Receivable		(4,089	)		(2,984	)
Inventory, Prepaid Expenses and Other Assets		21			(81	)
Accounts Payable and Accrued Expenses		28,285			(3,746	)
Other Assets and Liabilities		(9,990	)		(2,286	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		34,934			6,760
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		32			147
Contributions to Equity Method Investments		0			(2,852	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		73			1,224
Acquisitions of Undeveloped Acreage		(5,758	)		(16,844	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(60,787	)		(34,025	)
NET CASH USED IN INVESTING ACTIVITIES		(66,440	)		(52,350	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		0			(50,000	)
Proceeds from Long-Term Debt and Line of Credit		0			20,000
Repayments of Loans and Other Notes Payable		(318	)		(218	)
Debt Issuance Costs		(668	)		(37	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		0			(233	)
Proceeds from the Exercise of Stock Options		166			0
Distributions by the Partners of Consolidated Joint Ventures		(9	)		(41	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			70,583
NET CASH PROVIDED BY FINANCING ACTIVITIES		(829	)		40,054
NET DECREASE IN CASH		(32,335	)		(5,536	)
CASH—BEGINNING		43,975			11,796
CASH—ENDING	$	11,640		$	6,260
SUPPLEMENTAL DISCLOSURES
Interest Paid		397			1,491
Cash Paid for Income Taxes		0			0
NON-CASH ACTIVITIES
Equipment Financing		643			463

See accompanying notes to the unaudited consolidated financial statements

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REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian and Illinois Basins. 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, in addition to our developmental oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. 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. For purposes of consistency with current presentation, we have reclassified approximately $3.9 million from Wells and Facilities in Progress to Unevaluated Oil and Gas Properties on our Consolidated Balance Sheet as of December 31, 2012 and $0.3 million from Depreciation, Depletion, Amortization and Accretion to Interest Expense on our Consolidated Statement of Operations for the three months ended March 31, 2012, with no effect on previously reported net income, net income per share, accumulated deficit or stockholders’ equity.

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

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012.

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 4, 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. BUSINESS SEGMENT INFORMATION

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

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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 the three months ended March 31, 2013 and 2012 (in thousands):

	Exploration and Production			Field Services			Intercompany Eliminations			Consolidated Total
Three Months Ended March 31, 2013
Revenues	$	40,964		$	8,054		$	(1,548	)	$	47,470
Inter-Segment Revenues		0			(1,548	)		1,548			0
Total Revenues		40,964			6,506			0			47,470
Income (Loss) From Continuing Operations, Before Income Taxes	$	(6,066	)	$	2,163		$	(441	)	$	(4,344	)
Three Months Ended March 31, 2012
Revenues	$	31,528		$	2,499		$	(193	)	$	33,834
Inter-Segment Revenues		0			(193	)		193			0
Total Revenues		31,528			2,306			0			33,834
Income (Loss) From Continuing Operations, Before Income Taxes	$	5,906		$	598		$	(45	)	$	6,459
As of March 31, 2013
Total Assets	$	794,688		$	16,009		$	(7,243	)	$	803,454
As of December 31, 2012
Total Assets	$	766,599		$	12,166		$	(6,055	)	$	772,710

3. FUTURE ABANDONMENT COST

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

Accretion expense during the three-month periods ended March 31, 2013 and 2012 totaled approximately $0.6 million and $0.5 million, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.

$ in Thousands	March 31, 2013
Beginning Balance	$	24,822
Future Abandonment Obligation Incurred		234
Future Abandonment Obligation Settled		(146	)
Future Abandonment Obligation Revision of Estimated Obligation		160
Future Abandonment Obligation Accretion Expense		601
Total Future Abandonment Cost	$	25,671

4. 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 12-15 months to which we have responded by modifying our marketing efforts. During the first quarter of 2013, we entered an agreement to sell our remaining DJ Basin assets for approximately $3.1 million, subject to customary due diligence and title research. We expect this transaction to close in the second quarter of 2013. As of March 31, 2013, these assets were recorded on our Consolidated Balance Sheet at a carrying value of $2.1 million. Upon the completion of a sale, we will have no continuing activities in the DJ Basin or continuing cash flows from this region.

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These assets have been classified as Assets Held for Sale on our Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012, and the results of operations are reflected in Discontinued Operations in our Consolidated Statements of Operations. We have included $2.1 million and $2.3 million of net assets located in the DJ Basin as Assets Held for Sale on our Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012, respectively. We have included approximately $0.1 million of liabilities as Liabilities Related to Assets Held for Sale on our Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012. These liabilities primarily relate to Accounts Payable and Accrued Expenses.

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

	March 31,
($ in Thousands)	2013			2012
Revenues:
Oil, Natural Gas and NGL Sales	$	9		$	29
Total Operating Revenue		9			29
Costs and Expenses:
Production and Lease Operating Expense		46			86
General and Administrative Expense		11			287
Exploration Expense		53			332
Impairment Expense		0			8,270
Other Operating (Income) Expense		(3	)		3
Loss on Sale of Asset		4			144
Total Costs and Expenses		111			9,122
Loss from Discontinued Operations Before Income Taxes		(102	)		(9,093	)
Income Tax Benefit		41			3,738
Loss from Discontinued Operations, net of taxes	$	(61	)	$	(5,355	)
Production:
Crude Oil (Bbls)		147			344
Total (Mcfe)		882			2,064

5. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS

During the first quarter of 2013, we did not enter into any significant property acquisitions.

6. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In January 2013, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. ASU 2013-01 was issued to address implementation issues regarding the scope of ASU 2011-11. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. We adopted this ASU on January 1, 2013 with no material effect on our Consolidated Financial Statements.

7. CONCENTRATIONS OF CREDIT RISK

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 8, Long-term Debt, to our Consolidated Financial Statements). We have

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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 cash settlement date. For additional information, see Note 9, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the three months ended March 31, 2013, approximately 97.8% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 42.7% of commodity sales. We believe the growth in our Appalachian Basin operations will help us to minimize our future risks by diversifying our ratio of oil, NGLs and natural gas sales as well as the quantity of purchasers.

8. LONG-TERM DEBT

Senior Credit Facility

On March 27, 2013, we entered into a new senior secured revolving credit facility agreement with KeyBank National Association, as administrative agent (the “Administrative Agent”), Royal Bank of Canada, as syndication agent, SunTrust Bank, as documentation agent, and the lenders from time to time party thereto (the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are to be used to provide working capital for exploration and production operations and for general corporate purposes, and are limited by a borrowing base that is calculated based upon a valuation of our oil and gas properties. The borrowing base is $325.0 million; however, the maximum commitments of the lenders under the Senior Credit Facility are limited to $300.0 million as of March 31, 2013. In connection with our April 2012 offering of 8.875% senior notes due 2020, 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 from $300.0 million to $215.0 million (for additional information, see Note 19, Subsequent Events, to our Consolidated Financial Statements).

Within the Senior Credit Facility, a letter of credit subfacility exists for issuance of up to $25.0 million of letters of credit. Amounts borrowed under the Senior Credit Facility may be repaid and reborrowed at any time prior to the maturity date of March 27, 2018. As of March 31, 2013 and December 31, 2012, we had $0 drawn on the Senior Credit Facility. The revolving credit facility may be increased up to $500 million upon re-determinations of the borrowing base, consent of the lenders and other conditions described in the agreement. The borrowing base is re-determined by the bank group semi-annually. In certain circumstances, we may be required to prepay any loans that are outstanding.

At our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” or the “Alternate Base Rate” (each as defined below), plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of: (i) the London Interbank Offered Rate for deposits with a maturity comparable to the borrowings (the “LIBO Rate”) multiplied by (ii) the statutory reserve rate. The Alternative Base Rate is equal to the greater of: (i) KeyBank’s announced prime rate; (ii) the federal funds effective rate from time to time plus 0.5%; and (iii) Adjusted LIBO Rate for a one month interest period plus 1.0%. The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 175 to 275 basis points, and the applicable per annum margin, in the case of loans bearing interest at the Alternate Base Rate, ranges from 50 to 150 basis points, in each case, determined based upon our borrowing utilization at such date of determination. Upon the occurrence and continuance of an event of default all outstanding loans shall bear interest at a rate equal to 200 basis points per annum plus the then-effective rate of interest. Interest is payable on the last day of the relevant interest period (or at least every three months), in the case of loans bearing interest at the Adjusted LIBO Rate, and quarterly, in the case of loans bearing interest at the Alternate Base Rate.

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, NGLs and natural gas, calculated separately. For further information on our derivative instruments, see Note 9, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.

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

The Senior Credit Facility also requires that we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our

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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 is to not be less than 1.0 to 1.0. On that basis, our current ratio as of March 31, 2013 was 4.2 to 1.0. Additionally, the Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of EBITDAX for the period of four fiscal quarters ending on such day to interest expense for such period, known as our interest coverage ratio, is not to be less than 3.0 to 1.0. Our interest coverage ratio as of March 31, 2013 was 7.0 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the period of four fiscal quarters ending on such day is not to exceed 4.25 to 1.0. Our ratio of total debt to EBITDAX as of March 31, 2013 was 2.7 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.

8.875% Senior Notes Due 2020

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 “Senior Notes”). The net proceeds of the Senior Notes, after discounts and expenses, were approximately $242.2 million. Debt issuance costs of $6.1 million were recorded as Deferred Financing Costs and Other Assets—Net on our Consolidated Balance Sheet and are being amortized over the term of the Senior Notes as Interest Expense on our Consolidated Statements 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 Senior Notes at any time on or after December 1, 2016. We may also redeem up to 35% of the Senior 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 in control, we may be required to offer to purchase the Senior Notes from the holders. The Senior Notes will be fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. On April 26, 2013, we issued an additional $100.0 million in aggregate principal amount of 8.875% senior notes due 2020 in a private offering as additional notes to the $250.0 million aggregate principal amount of the Senior Notes issued on December 12, 2012 (for additional information, see Note 19, Subsequent Events, to our Consolidated Financial Statements).

In addition to our Senior Credit Facility and our Senior 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 other obligations consisted of the following at March 31, 2013 and December 31, 2012:

($ in Thousands)	March  31, 2013 (Unaudited)			December 31, 2012
8.875% Senior Notes Due 2020	$	250,000		$	250,000
Discount on Senior Notes		(1,704	)		(1,742	)
Senior Line of Credit(a)		0			0
Capital Leases and Other Obligations(a)		3,012			2,677
Total Debts		251,308			250,935
Less Current Portion of Long-Term Debt(b)		(1,845	)		(1,686	)
Total Long-Term Debt	$	249,463		$	249,249

^(a)  The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. Loans made under the Senior Credit Facility mature on March 27, 2018, and in certain circumstances, we may be required to prepay the loans. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2013 was approximately 3.2%.

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

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9. FAIR VALUE OF FINANCIAL AND DERIVATIVE INSTRUMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil, NGLs and natural gas. To mitigate a portion of the exposure to adverse market changes, we enter into oil, NGL and natural gas commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor on the settlement dates, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling on the settlement dates, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of March 31, 2013, our oil, NGL and natural gas derivative commodity instruments consisted of fixed rate swap contracts, collars, swaptions, puts 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 other income or expense on our Consolidated Statements of Operations under the heading Gain (Loss) on Derivatives, Net.

Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Swaption agreements provide options to counterparties to extend swaps into subsequent years.

We enter into the majority of our derivative arrangements with four counterparties and have master netting agreements in place. We present our derivatives as gross assets or liabilities on our Consolidated Balance Sheets and do not offset the values of any contracts that are subject to master netting agreements. We do not obtain collateral to support the derivative agreements, but monitor the financial viability of our counterparties and believe our credit risk is minimal on these transactions. For additional information on the credit risk with regards to our counterparties, see Note 7, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our derivatives are designated for hedge accounting but are, to a degree, an economic offset to our oil, natural gas and NGL 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 (Loss) on Derivatives, Net under Other Income (Expense).

We received net payments of $3.7 million and $3.8 million under these commodity derivative instruments during the three-month periods ended March 31, 2013 and 2012, respectively. Unrealized gains and losses associated with our commodity derivative instruments amounted to a loss of $12.2 million and a gain of $3.7 million for the three months ended March 31, 2013 and 2012, respectively.

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The following table summarizes the location and amounts of gains and losses on derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012 ($ in thousands):

	Three Months Ended March 31, 2013									Three Months Ended March 31, 2012
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total			Realized Gains (Losses)			Unrealized Gains (Losses)			Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	0		$	104		$	104		$	0		$	535		$	535
Mark-to-market fair value adjustments		0			(857	)		(857	)		0			(2,888	)		(2,888	)
Settlement of contracts(a)		(162	)		0			(162	)		(212	)		0			(212	)
Crude Oil Total		(162	)		(753	)		(915	)		(212	)		(2,353	)		(2,565	)
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0			(2,642	)		(2,642	)		0			(2,601	)		(2,601	)
Mark-to-market fair value adjustments		0			(8,690	)		(8,690	)		0			8,608			8,608
Settlement of contracts(a)		3,691			0			3,691			3,997			0			3,997
Natural Gas Total		3,691			(11,332	)		(7,641	)		3,997			6,007			10,004
Natural Gas Liquids
Reclassification of settled contracts included in prior periods mark-to-market adjustment		1			(134	)		(133	)		0			0			0
Mark-to-market fair value adjustments		0			8			8			0			0			0
Settlement of contracts(a)		141			0			141			0			0			0
Natural Gas Liquids Total		142			(126	)		16			0			0			0
Gain (Loss) on Derivatives, Net	$	3,671		$	(12,211	)	$	(8,540	)	$	3,785		$	3,654		$	7,439

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

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Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $2.4 million and a net asset of $9.8 million at March 31, 2013 and December 31, 2012, respectively.

As of March 31, 2013, we had approximately 95.9% and 74.2% of our current oil production on an annualized basis hedged through 2013 and 2014, respectively, approximately 93.8%, 74.8% and 15.7% of our current gas production on an annualized basis hedged through 2013, 2014 and 2015, respectively, and approximately 60.6% and 63.9% of our current NGL production on an annualized basis hedged through 2013 and 2014, respectively. Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2013 consisted of:

Period	Volume		Put Option		Floor		Ceiling		Swap		Fair Market Value ($ in Thousands)
Oil
2013—Collar		165,000 Bbls	$	0	$	79.45	$	103.00	$	0	$	(178	)
2013—Swap		360,000 Bbls		0		0		0		93.02		(1,322	)
2013—Three Way Collar		45,000 Bbls		65.00		85.00		100.00		0		(66	)
2014—Three Way Collar		360,000 Bbls		69.00		84.18		104.27		0		(42	)
2014—Collar		60,000 Bbls		0		90.00		97.65		0		68
2014—Deferred Put Spread		168,000 Bbls		75.00		90.00		0		0		(201	)
		1,158,000 Bbls									$	(1,741	)
Natural Gas
2013—Swap		6,190,000 Mcf	$	0	$	0	$	0	$	3.87	$	(1,695	)
2013—Three Way Collar		1,890,000 Mcf		3.35		4.17		4.88		0		328
2013—Collar		2,520,000 Mcf		0		4.77		5.68		0		1,823
2013—Put		1,980,000 Mcf		0		5.00		0		0		1,456
2013—Swaption		900,000 Mcf		0		0		0		4.50		(427	)
2014—Call		1,800,000 Mcf		0		0		5.00		0		(370	)
2014—Three Way Collar		6,000,000 Mcf		3.00		3.95		4.64		0		(278	)
2014—Swap		4,740,000 Mcf		0		0		0		3.96		(1,225	)
2014—Collar		1,800,000 Mcf		0		3.51		4.43		0		(397	)
2015—Three Way Collar		1,800,000 Mcf		3.37		4.15		4.59		0		(178	)
2015—Swap		1,200,000 Mcf		0		0		0		4.18		(107	)
		30,820,000 Mcf										(1,070	)
Natural Gas Liquids
2013—Swap		243,000 Bbls	$	0	$	0	$	0	$	57.48	$	431
2014—Swap		18,000 Bbls		0		0		0		47.46		(21	)
		261,000 Bbls									$	410

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The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012 is summarized below ($ in thousands):

	March 31, 2013			December 31, 2012
Short-Term Derivative Assets:
Crude Oil—Collars	$	16		$	90
Crude Oil—Three Way Collars		9			0
Natural Gas Liquids—Swaps		572			535
Natural Gas—Swaps		406			2,416
Natural Gas—Swaption		0			354
Natural Gas—Three-Way Collars		460			1,021
Natural Gas—Collars		1,823			4,211
Natural Gas—Puts		1,456			3,378
Total Short-Term Derivative Assets	$	4,742		$	12,005
Long-Term Derivative Assets:
Crude Oil—Collars	$	51		$	0
Crude Oil—Three Way Collar		26			0
Natural Gas—Swaps		21			239
Natural Gas—Three Way Collar		52			465
Total Long-Term Derivative Assets	$	150		$	704
Total Derivative Assets	$	4,892		$	12,709
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(177	)	$	(307	)
Crude Oil—Swaps		(1,322	)		(217	)
Crude Oil—Three-Way Collars		(85	)		(45	)
Crude Oil—Deferred Put Spread		(50	)		0
Natural Gas Liquids—Swaps		(162	)		0
Natural Gas—Three-Way Collars		(202	)		(35	)
Natural Gas—Collars		(98	)		0
Natural Gas—Call		(92	)		0
Natural Gas—Swaption		(427	)		0
Natural Gas—Swaps		(2,457	)		(785	)
Total Short-Term Derivative Liabilities	$	(5,072	)	$	(1,389	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	(58	)	$	(509	)
Crude Oil—Deferred Put Spread		(151	)		0
Natural Gas—Swaps		(997	)		(434	)
Natural Gas—Three-Way Collars		(438	)		(35	)
Natural Gas—Call		(278	)		(366	)
Natural Gas—Collars		(299	)		(166	)
Total Long-Term Derivative Liabilities	$	(2,221	)	$	(1,510	)
Total Derivative Liabilities	$	(7,293	)	$	(2,899	)

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

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categorized in Level 2.

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

During the three months ended March 31, 2013, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value ($ in thousands):

				Fair Value Measurements at March 31, 2013 Using:
	Total Carrying Value as of March 31, 2013			Quoted Prices in Active Markets for Identical Assets (Level  1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivatives(a)— commodity swaps and collars	$	(2,401	)	$	0	$	(2,401	)	$	0
Future Abandonment Costs	$	(25,671	)	$	0	$	0		$	(25,671	)

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

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 March 31, 2013 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 March 31, 2013 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 NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu Propane (“MBP”). The fair values attributable to our NGL derivative contracts as of March 31, 2013 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.

Future Abandonment Cost

We report the fair value of future abandonment costs on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of future abandonment costs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; estimated probabilities, amounts and timing of settlements; estimated plugging costs; the credit-adjusted risk-free rate to be used; and inflation rates. The most significant inputs used in the determination of future abandonment costs are the estimated costs to plug and abandon our wells. Significant changes in the estimated cost to plug and abandon our wells can cause significant changes in the fair value measurement of our future abandonment costs due to the large number of wells that we operate. These inputs are unobservable, and thus result in a Level 3 classification. Refer to Note 3, Future Abandonment Cost, of our Consolidated Financial Statements for further information on future abandonment costs, which include a reconciliation of the beginning and ending balances that represent the entirety of our Level 3 fair value measurements.

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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:

	March 31, 2013				December 31, 2012
$ in Thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
8.875% Senior Notes due 2020	$	250,000	$	265,000	$	250,000	$	249,063
Capital Leases and Other Obligations		3,012		2,892		2,677		2,524
Total	$	253,012	$	267,892	$	252,677	$	251,597

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy. The fair value of our 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 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 and other obligations would be classified as Level 3 in the fair value hierarchy.

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

10. INCOME TAXES

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

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

	Three Months Ended March  31,
	2013			2012
Income Tax (Expense) Benefit	$	2,004		$	(2,631	)
Effective Tax Rate		42.0	%		41.4	%

For the three months ended March 31, 2013, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state taxes. For the three months ended March 31, 2012, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily to state taxes, which was in part offset by downward revisions in relation to permanent differences, changes to estimated future state rates and state net operating loss carryforward true-ups.

No income tax payments were made during the three months ended March 31, 2013 and 2012.

11. CAPITAL STOCK

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of March 31, 2013 and December 31, 2012, we had 53,227,718 and 53,213,264 shares of common stock outstanding, respectively. There were no shares of preferred stock outstanding as of March 31, 2013 and December 31, 2012.

12. EMPLOYEE BENEFIT AND EQUITY PLANS

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

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value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.

2007 Long-Term Incentive Plan

We have granted stock options, stock appreciation rights and restricted stock awards to various employees, non-employee contractors and non-employee directors under the terms of our 2007 Long-Term Incentive Plan, as amended (the “Plan”). The Plan is administered by the Compensation Committee of our Board of Directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are: selecting participants to receive awards; determining the form, amount and other terms and conditions of awards; interpreting the provisions of the Plan or any award agreement; and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Internal Revenue Code or covered employees, are intended to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.

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

Stock Options

Stock options represent the right to purchase shares of common stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, 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 three months ended March 31, 2013 and 2012, we did not issue options to purchase shares of our common stock.

Stock-based compensation expense relating to stock options outstanding for the three months ended March 31, 2013 and 2012 totaled $0.1 million and $0.1 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 three months ended March 31, 2013, was approximately $0.1 million. The total tax benefit for the three months ended March 31, 2013 was negligible. There were no stock option exercises during the three months ended March 31, 2012.

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A summary of the status of our issued and outstanding stock options as of March 31, 2013 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding At 3/31/13		Weighted-Average Exercise Price		Number Exercisable At 3/31/13		Weighted-Average Exercise Price
$	5.04		46,041	$	5.04		46,041	$	5.04
$	9.50		100,000	$	9.50		100,000	$	9.50
$	9.99		179,833	$	9.99		179,833	$	9.99
$	10.42		29,548	$	10.42		19,699	$	10.42
$	11.87		3,500	$	11.87		1,166	$	11.87
$	12.50		19,139	$	12.50		12,758	$	12.50
$	13.01		18,526	$	13.01		12,350	$	13.01
$	13.19		50,000	$	13.19		0	$	13.19
$	19.92		5,000	$	19.92		5,000	$	19.92
$	22.34		30,000	$	22.34		30,000	$	22.34
$	23.28		4,000	$	23.28		4,000	$	23.28
			485,587	$	10.98		410,847	$	10.66

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at March 31, 2013 were 4.6 years and $2.9 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at March 31, 2013 were 4.7 years and $2.6 million, respectively. As of March 31, 2013, unrecognized compensation expense related to stock options totaled approximately $0.2 million, which will be recognized over a weighted average period of 1.4 years.

Restricted Stock Awards

During the three-month period ended March 31, 2013, the Compensation Committee approved the issuance of an aggregate of 33,055 shares of restricted common stock to 13 employees and three non-employee contractors. During the three-month period ended March 31, 2012, the Compensation Committee approved the issuance of an aggregate of 14,516 shares of restricted stock to nine employees. The shares granted 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 through 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 shares of common stock are valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of grant. Upon a “change in control” of us, as such term is defined in the Plan, restrictions on time vesting and performance-based vesting restricted stock will lapse to varying degrees as outlined in each award agreement. Compensation expense associated with the restricted stock awards is recognized on a straight-line basis over the vesting period.

Compensation expense associated with restricted stock awards is recognized on a straight-line basis over the vesting period and is periodically adjusted for estimated forfeiture rates and estimated satisfaction of performance-based goals. Compensation expense associated with restricted stock awards totaled $1.2 million and $0.4 million for the three-month periods ended March 31, 2013 and 2012, respectively. As of March 31, 2013, total unrecognized compensation cost related to restricted common stock grants was approximately $4.1 million, which will be recognized over a weighted average period of 2.0 years.

Certain of our outstanding restricted stock awards 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	%

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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:

	Three Months Ended March 31, 2013	Year Ended December 31, 2012
Expected Dividend Yield	0.0%	0.0%
Risk-Free Interest Rate	0.3%	0.3%
Expected Volatility—Rex Energy	54.4%	54.4%
Expected Volatility—Peer Group	31.2%-58.6%	31.2%-58.6%
Market Index	37.0%	37.0%
Expected Life	Three Years	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.

A summary of the restricted stock activity for the three months ended March 31, 2013 is as follows:

	Number of Shares			Weighted Average Grant  Date Fair Value
Restricted stock awards, as of December 31, 2012		1,431,573		$	12.45
Awards		33,055			13.08
Forfeitures		(35,267	)		11.64
Vested		(115,841	)		11.58
Restricted stock awards, as of March 31, 2013		1,313,520		$	12.57

13. COMMITMENTS AND CONTINGENCIES

Legal Reserves

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

The accrual of reserves for legal matters is included in Accrued Expenses on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

There have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

Environmental

Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate

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whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of March 31, 2013, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

At March 31, 2013, we had posted $1.0 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of March 31, 2013, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three months ended March 31, 2013 and 2012 was $0.1 million for each period. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):

2013	$	675
2014		842
2015		807
2016		815
2017		823
Thereafter		133
Total	$	4,095

Capacity Reservation

During the second quarter of 2012, 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 $4.9 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, assuming our average working interest in the region of approximately 70%. Charges incurred for processing capacity with MarkWest were negligible during the three-month periods ended March 31, 2013 and 2012.

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 $2.2 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 $6.3 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 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.

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For the three-month periods ended March 31, 2013 and 2012, we incurred expenses related to the transportation and marketing of our oil, natural gas and NGLs of approximately $5.0 million and $2.7 million, respectively. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows ($ in thousands):

	Total
2013	$	6,721
2014		12,495
2015		19,584
2016		26,712
2017		32,552
Thereafter		341,576
Total	$	439,640

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 March 31, 2013, the remaining drilling carry obligation balance was approximately $10.8 million.

We are to commence the drilling of at least three Utica Shale wells by November 15 of each year until the carry obligation has been satisfied, with credits given to additional wells drilled beyond the annual commitment. We currently estimate the commitment for each well drilled and completed for our working interest and that of MFC to be approximately $8.0 million to $9.0 million. We have until June 15, 2013 to terminate the agreement. Should we not comply with the drilling commitments or terminate the agreement outside of the aforementioned termination parameter, we would be responsible for payment of the remaining drilling carry obligation at that time.

Pennsylvania Impact Fee

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

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

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

For wells spud prior to 2012, the first year fee (considered to be 2011) was due on September 1, 2012. We fully accrued for this portion of the fee as a current liability in first quarter 2012 in the amount of $2.8 million. Subsequent to the first payment, all fees owed will be due on April 1 of each year. For the three month periods ended March 31, 2013 and 2012, we recorded expense of approximately $0.6 million and $3.4 million, respectively, related to the Pennsylvania Impact Fee. Approximately $2.8 million of the fees incurred in the first quarter of 2012 represents the retroactive portion of the impact fee for wells spud prior to 2012. We are

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recording the accrual of the impact fees as Production and Lease Operating Expense.

Other

In addition to the Asset Retirement Obligation discussed in Note 3, Future Abandonment Costs, to our Consolidated Financial Statements, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. These amounts totaled $0.3 million at March 31, 2013 and December 31, 2012 and are included in Other Liabilities on our Consolidated Balance Sheets.

14. EARNINGS (LOSS) PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based vesting criteria. Diluted income per common share includes the assumed exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market based, given that the hypothetical effect is not anti-dilutive. Stock options to purchase 114,246 shares of common stock and performance-based restricted stock awards of 719,479 shares of common stock for the three-month period ended March 31, 2013 were outstanding but not included in the computations of diluted net loss per share calculations due to our net loss from continuing operations, for which the result would be anti-dilutive. Stock options to purchase 637,652 shares of common stock for the three-month period ended March 31, 2012 were outstanding but not included in the computations of diluted net income per share because the grant prices were greater than the average market price of the common shares, which has anti-dilutive effect on the computation. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

	Three Months Ended March  31,
	2013			2012
Numerator:
Net Income (Loss) From Continuing Operations, Less Noncontrolling Interests	$	(2,773	)	$	3,727
Net Loss From Discontinued Operations		(61	)		(5,355	)
Net Loss	$	(2,834	)	$	(1,628	)
Denominator:
Weighted Average Common Shares Outstanding—Basic		52,367			48,744
Effect of Dilutive Securities:
Employee Stock Options		0			61
Employee Performance-Based Restricted Stock Awards		0			888
Weighted Average Common Shares Outstanding—Diluted		52,367			49,693
Earnings (loss) per Common Share:
Basic—Net Income (Loss) From Continuing Operations	$	(0.05	)	$	0.08
—Net Loss From Discontinued Operations		0.00			(0.11	)
—Net Loss	$	(0.05	)	$	(0.03	)
Diluted—Net Income (Loss) From Continuing Operations	$	(0.05	)	$	0.08
—Net Loss From Discontinued Operations		0.00			(0.11	)
—Net Loss	$	(0.05	)	$	(0.03	)

15. CONSOLIDATED SUBSIDIARIES

Our consolidated subsidiaries make up 100.0% of our field services segment. For additional information, see Note 2, 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. The return of our initial capital investment occurred in April 2013 and the change in our ownership percentage took effect on April 1, 2013.

We fully consolidate the accounts of Water Solutions in our financial statements and accounted 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 March 31, 2013. There were no cash contributions during the first three

24

months of 2013 and 2012. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of March 31, 2013 and December 31, 2012, with no restrictions or obligations to use certain assets to settle associated liabilities:

($ in Thousands)	As of March 31, 2013			As of December 31, 2012
Assets
Cash and Cash Equivalents	$	361		$	741
Accounts Receivable		6,786			3,360
Inventory, Prepaid Expenses and Other		48			13
Other Property and Equipment		4,588			3,560
Wells and Facilities in Progress		217			221
Accumulated Depreciation, Depletion and Amortization		(740	)		(501	)
Deferred Financing Costs and Other Assets—Net		182			199
Total Assets	$	11,442		$	7,593
Liabilities
Accounts Payable	$	2,181		$	1,554
Accrued Expenses		2,069			1,036
Senior Secured Line of Credit and Long-Term Debt		1,036			965
Total Liabilities	$	5,286		$	3,555

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 March 31, 2013, R.E. Gas owned a 51% membership interest in NorthStar #3, and 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 March 31, 2013, the amount owed to us under the promissory note was $4.6 million.

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

The carrying amount and classifications of NorthStar #3 assets and liabilities as of March 31, 2013 and December 31, 2012 are as follows, with no restrictions or obligations to use certain assets to settle associated liabilities:

	March 31, 2013 (in  thousands)		December 31, 2012 (in  thousands)
ASSETS
Cash and Cash Equivalents	$	8	$	14
Wells and Facilities in Progress		4,567		4,559
Total Assets	$	4,575	$	4,573
LIABILITIES
Accounts Payable	$	0	$	6
Note Payable		4,633		4,633
Total Liabilities	$	4,633	$	4,639

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16. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our Appalachian Basin operations. We recorded our investment in RW Gathering of approximately $16.8 million and $17.0 million as of March 31, 2013 and December 31, 2012, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During the first three months of 2013, we did not make any capital contributions to RW Gathering, as compared to the contributions of approximately $1.5 million in cash to RW Gathering to support current pipeline and gathering line construction in the first three months of 2012. RW Gathering recorded net losses from continuing operations of $0.4 million for each of the three months ended March 31, 2013 and 2012, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Our share of the net loss is recorded on the Statements of Operations as Gain (Loss) on Equity Method Investments.

During the three-month periods ended March 31, 2013 and 2012, we incurred approximately $0.2 million and $0.3 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 March 31, 2013 and December 31, 2012, there were no receivables due from RW Gathering to us.

Keystone Midstream Services, LLC

On May 29, 2012, we closed the sale of our ownership in Keystone Midstream, which we had accounted for as an equity method investment.

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. During the three months ended March 31, 2012, we contributed approximately $1.4 million to Keystone Midstream primarily to support the construction of cryogenic gas processing plants. Keystone Midstream recorded a net income from continuing operations of $0.1 million for the three month period ended March 31, 2012. 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.

17. IMPAIRMENT EXPENSE

For the three months ended March 31, 2013 and 2012, we incurred approximately $0.1 million and $2.8 million in impairment expenses, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first three months of 2013 and 2012 is primarily related to acreage in our non-operated dry gas region of Clearfield County, Pennsylvania. These leases are approaching expiration and there currently exists no plans to extend the leases or develop the acreage. As of March 31, 2013, we continued to carry the costs of undeveloped properties of approximately $171.9 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

18. EXPLORATION EXPENSE

For the three months ended March 31, 2013 and 2012, we incurred approximately $2.0 million and $1.1 million in exploration expenses, respectively. The expense incurred in 2013 was due to geological and geophysical type expenditures and delay rental payments. Approximately $0.8 million of the expense incurred in 2012 was due to geological and geophysical type expenditures and delay rental payments primarily associated with leases in the Appalachian Basin. An additional $0.3 million related to the plugging of two exploratory Marcellus Shale wells that were spud during 2011 in Butler County, Pennsylvania. Minimal drilling was completed on these wells before a strategic decision was made to abandon the well sites and defer capital to other leases in the development plan and hold the acreage by production.

19. 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

26

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.

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20. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of March 31, 2013, we had outstanding $250.0 million of Senior Notes due 2020, as shown in Note 8, 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 March 31, 2013:

• 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 March 31, 2013, 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 March 31, 2013 and December 31, 2012, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for the three months ending March 31, 2013 and March 31, 2012.

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REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF MARCH 31, 2013

($ 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	$	5,140		$	475		$	6,025		$	0		$	11,640
Accounts Receivable		27,924			6,801			0			(5,623	)		29,102
Taxes Receivable		0			0			6,396			0			6,396
Short-Term Derivative Instruments		4,742			0			0			0			4,742
Assets Held For Sale		0			2,138			0			0			2,138
Inventory, Prepaid Expenses and Other		1,236			48			17			0			1,301
Total Current Assets		39,042			9,462			12,438			(5,623	)		55,319
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		539,134			0			0			(1,496	)		537,638
Unevaluated Oil and Gas Properties		171,901			0			0			0			171,901
Other Property and Equipment		48,834			5,483			0			0			54,317
Wells and Facilities in Progress		102,734			4,776			0			(296	)		107,214
Pipelines		6,125			0			0			0			6,125
Total Property and Equipment		868,728			10,259			0			(1,792	)		877,195
Less: Accumulated Depreciation, Depletion and Amortization		(155,638	)		(925	)		0			173			(156,390	)
Net Property and Equipment		713,090			9,334			0			(1,619	)		720,805
Deferred Financing Costs and Other Assets—Net		2,426			182			7,772			0			10,380
Equity Method Investments		16,800			0			0			0			16,800
Intercompany Receivables		2,338			0			474,556			(476,894	)		0
Investment in Subsidiaries – Net		(341	)		3,989			193,598			(197,246	)		0
Long-Term Derivative Instruments		150			0			0			0			150
Total Assets	$	773,505		$	22,967		$	688,364		$	(681,382	)	$	803,454
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	43,081		$	2,181		$	0		$	(990	)	$	44,272
Accrued Expenses		28,505			2,068			7,083			0			37,656
Short-Term Derivative Instruments		5,072			0			0			0			5,072
Current Deferred Tax Liability		0			0			565			0			565
Liabilities Related to Assets Held For Sale		0			50			0			0			50
Total Current Liabilities		76,658			4,299			7,648			(990	)		87,615
8.875% Senior Notes Due 2020		0			0			250,000			0			250,000
Discount on Senior Notes		0			0			(1,704	)		0			(1,704	)
Senior Secured Line of Credit and Long-Term Debt		131			5,669			0			(4,633	)		1,167
Long-Term Derivative Instruments		2,221			0			0			0			2,221
Long-Term Deferred Tax Liability		0			0			21,491			0			21,491
Other Deposits and Liabilities		5,739			0			0			0			5,739
Future Abandonment Cost		25,671			0			0			0			25,671
Intercompany Payables		400,510			76,384			0			(476,894	)		0
Total Liabilities		510,930			86,352			277,435			(482,517	)		392,200
Stockholders’ Equity
Common Stock, $0.001 par value per share, 100,000,000 shares authorized and 53,227,718 shares issued and outstanding on March 31, 2013		0			0			52			0			52
Additional Paid-In Capital		177,145			2,889			452,431			(180,033	)		452,432
Accumulated Earnings (Deficit)		85,430			(67,042	)		(41,554	)		(19,263	)		(42,429	)
Rex Energy Stockholders’ Equity		262,575			(64,153	)		410,929			(199,296	)		410,055
Noncontrolling Interests		0			768			0			431			1,199
Total Stockholders’ Equity		262,575			(63,385	)		410,929			(198,865	)		411,254
Total Liabilities and Stockholders’ Equity	$	773,505		$	22,967		$	688,364		$	(681,382	)	$	803,454

29

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2013

($ in Thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	40,940		$	0		$	0		$	0		$	40,940
Field Services Revenue		0			8,053			0			(1,547	)		6,506
Other Revenue		24			0			0			0			24
TOTAL OPERATING REVENUE		40,964			8,053			0			(1,547	)		47,470
OPERATING EXPENSES
Production and Lease Operating Expense		13,397			3			0			0			13,400
General and Administrative Expense		6,071			489			1,271			(35	)		7,796
Gain on Disposal of Asset		(10	)		0			0			0			(10	)
Impairment Expense		66			0			0			0			66
Exploration Expense		2,044			0			0			0			2,044
Depreciation, Depletion, Amortization and Accretion		10,913			267			0			(23	)		11,157
Field Services Operating Expense		0			5,138			0			(1,083	)		4,055
Other Operating Expense		444			0			0			0			444
TOTAL OPERATING EXPENSES		32,925			5,897			1,271			(1,141	)		38,952
INCOME (LOSS) FROM OPERATIONS		8,039			2,156			(1,271	)		(406	)		8,518
OTHER INCOME (EXPENSE)
Interest Expense		(9	)		(12	)		(3,984	)		0			(4,005	)
Loss on Derivatives, Net		(8,540	)		0			0			0			(8,540	)
Other Expense		(104	)		0			0			(35	)		(139	)
Loss From Equity Method Investments		(178	)		0			0			0			(178	)
Income (Loss) From Equity in Consolidated Subsidiaries		(10	)		10			31			(31	)		0
TOTAL OTHER EXPENSE		(8,841	)		(2	)		(3,953	)		(66	)		(12,862	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(802	)		2,154			(5,224	)		(472	)		(4,344	)
Income Tax (Expense) Benefit		332			(718	)		2,390			0			2,004
INCOME (LOSS) FROM CONTINUING OPERATIONS		(470	)		1,436			(2,834	)		(472	)		(2,340	)
Loss From Discontinued Operations, Net of Income Taxes		0			(61	)		0			0			(61	)
NET INCOME (LOSS)		(470	)		1,375			(2,834	)		(472	)		(2,401	)
Net Income Attributable to Noncontrolling Interests		0			433			0			0			433
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(470	)	$	942		$	(2,834	)	$	(472	)	$	(2,834	)

30

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDING MARCH 31, 2013

($ in Thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(470	)	$	1,375		$	(2,834	)	$	(472	)	$	(2,401	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		178			0			0			0			178
Non-Cash Expenses		2			8			1,600			0			1,610
Depreciation, Depletion, Amortization and Accretion		10,913			267			0			(23	)		11,157
Deferred Income Tax Expense (Benefit)		(332	)		614			(2,390	)		0			(2,108	)
Unrealized (Gain) Loss on Derivatives		12,211			0			0			0			12,211
Gain on Sale of Assets and Equity Method Investments		(10	)		4			0			0			(6	)
Impairment Expense		66			0			0			0			66
Changes in operating assets and liabilities
Accounts Receivable		32,828			(3,409	)		(34,256	)		748			(4,089	)
Inventory, Prepaid Expenses and Other Assets		41			(29	)		9			0			21
Accounts Payable and Accrued Expenses		21,213			1,604			5,468			0			28,285
Other Assets and Liabilities		(9,990	)		0			0			0			(9,990	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		66,650			434			(32,403	)		253			34,934
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		707			4			6			(717	)		0
Proceeds from Joint Venture Acreage Management		32			0			0			0			32
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other assets		(60	)		133			0			0			73
Acquisitions of Undeveloped Acreage		(5,756	)		(2	)		0			0			(5,758	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(60,445	)		(806	)		0			464			(60,787	)
NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES		(65,522	)		(671	)		6			(253	)		(66,440	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable		(215	)		(103	)		0			0			(318	)
Debt Issuance Costs		0			0			(668	)		0			(668	)
Proceeds from the Exercise of Stock Options		0			0			166			0			166
Distributions by the Partners of Consolidated Joint Ventures		0			(9	)		0			0			(9	)
NET CASH USED IN FINANCING ACTIVITIES		(215	)		(112	)		(502	)		0			(829	)
NET INCREASE (DECREASE) IN CASH		913			(349	)		(32,899	)		0			(32,335	)
CASH—BEGINNING		4,227			824			38,924			0			43,975
CASH—ENDING	$	5,140		$	475		$	6,025		$	0		$	11,640

31

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF 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		165,503			0			0			0			165,503
Other Property and Equipment		45,613			4,455			0			5			50,073
Wells and Facilities in Progress		88,204			4,780			0			(71	)		92,913
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		$	(643,446	)	$	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 Deficit		86,326			(69,144	)		(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

32

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 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	$	31,483		$	0		$	0		$	0		$	31,483
Field Services Revenue		0			2,500			0			(194	)		2,306
Other Revenue		70			0			0			(25	)		45
TOTAL OPERATING REVENUE		31,553			2,500			0			(219	)		33,834
OPERATING EXPENSES
Production and Lease Operating Expense		12,295			4			0			0			12,299
General and Administrative Expense		4,686			177			557			(9	)		5,411
Loss on Disposal of Asset		26			0			0			0			26
Impairment Expense		2,727			66			0			0			2,793
Exploration Expense		1,092			0			0			0			1,092
Depreciation, Depletion, Amortization and Accretion		9,501			56			0			(13	)		9,544
Field Services Operating Expense		0			1,617			0			(161	)		1,456
Other Operating Expense		326			0			0			0			326
TOTAL OPERATING EXPENSES		30,653			1,920			557			(183	)		32,947
INCOME (LOSS) FROM OPERATIONS		900			580			(557	)		(36	)		887
OTHER INCOME (EXPENSE)
Interest Expense		(17	)		(1	)		(1,721	)		0			(1,739	)
Gain on Derivatives, Net		7,439			0			0			0			7,439
Other Income (Expense)		15			0			0			(9	)		6
Loss From Equity Method Investments		(134	)		0			0			0			(134	)
Income (Loss) From Equity in Consolidated Subsidiaries		(22	)		22			(312	)		312			0
TOTAL OTHER INCOME (EXPENSE)		7,281			21			(2,033	)		303			5,572
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		8,181			601			(2,590	)		267			6,459
Income Tax (Expense) Benefit		(3,394	)		(198	)		961			0			(2,631	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		4,787			403			(1,629	)		267			3,828
Loss From Discontinued Operations, Net of Income Taxes		0			(5,355	)		0			0			(5,355	)
NET INCOME (LOSS)		4,787			(4,952	)		(1,629	)		267			(1,527	)
Net Income Attributable to Noncontrolling Interests		0			101			0			0			101
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	4,787		$	(5,053	)	$	(1,629	)	$	267		$	(1,628	)

33

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDING MARCH 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)	$	4,787		$	(4,952	)	$	(1,629	)	$	267		$	(1,527	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Gain From Equity Method Investments		134			0			0			0			134
Non-Cash Expense (Income)		(14	)		(1	)		489			0			474
Depreciation, Depletion, Amortization and Accretion		9,501			56			258			(13	)		9,802
Deferred Income Tax Expense (Benefit)		3,394			(3,541	)		(961	)		0			(1,108	)
Unrealized Gain on Derivatives		(3,654	)		0			0			0			(3,654	)
Dry Hole Expense		254			249			0			0			503
Loss on Sale of Assets and Equity Method Investments		26			144			0			0			170
Impairment Expense		2,728			8,335			0			0			11,063
Changes in operating assets and liabilities
Accounts Receivable		35,499			577			(38,991	)		(69	)		(2,984	)
Inventory, Prepaid Expenses and Other Assets		(92	)		(2	)		13			0			(81	)
Accounts Payable and Accrued Expenses		(2,979	)		(735	)		(17	)		(15	)		(3,746	)
Other Assets and Liabilities		(2,004	)		(282	)		0			0			(2,286	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		47,580			(152	)		(40,838	)		170			6,760
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(2,837	)		2,539			468			(170	)		0
Proceeds from Joint Venture Acreage Management		147			0			0			0			147
Contributions to Equity Method Investments		0			(2,852	)		0			0			(2,852	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other assets		3			1,221			0			0			1,224
Acquisitions of Undeveloped Acreage		(16,843	)		(1	)		0			0			(16,844	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(33,933	)		(150	)		58			0			(34,025	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(53,463	)		757			526			(170	)		(52,350	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			0			20,000			0			20,000
Repayments of Long-Term Debt and Lines of Credit		0			0			(50,000	)		0			(50,000	)
Repayments of Loans and Other Notes Payable		(204	)		(14	)		0			0			(218	)
Debt Issuance Costs		0			0			(37	)		0			(37	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		0			0			(233	)		0			(233	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			0			70,583			0			70,583
Distributions by the Partners of Consolidated Joint Ventures		0			(41	)		0			0			(41	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(204	)		(55	)		40,313			0			40,054
NET INCREASE (DECREASE) IN CASH		(6,087	)		550			1			0			(5,536	)
CASH—BEGINNING		11,337			409			50			0			11,796
CASH—ENDING	$	5,250		$	959		$	51		$	0		$	6,260

34