Rex Energy 10-Q 2013 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

OR

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

For the transition period from                    to                    .

Commission file number: 001-33610

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

366 Walker Drive

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

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

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

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

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

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

53,596,422 common shares were outstanding on August 2, 2013.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD JUNE 30, 2013

INDEX

		PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements		4
	Consolidated Balance Sheets As of June 30, 2013 (Unaudited) and December 31, 2012		4
	Consolidated Statements of Operations (Unaudited) for the three and six-month periods ended June  30, 2013 and June 30, 2012		5
	Consolidated Statement of Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) (Unaudited) for the six-month period ended June 30, 2013		6
	Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2013 and June 30, 2012		7
	Notes to Consolidated Financial Statements (Unaudited)		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		45
Item 4.	Controls and Procedures		46
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		47
Item 1A.	Risk Factors		47
Item 6.	Exhibits		47
SIGNATURES			48
EXHIBIT INDEX			49

2

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

• economic conditions in the United States and globally;

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

• volatility in oil, natural gas and natural gas liquid (“NGL”) pricing;

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

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

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

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

• drilling and operating risks;

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

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

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

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

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

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

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

• changes in our drilling plans and related budgets;

• the success of prospect development and property acquisitions;

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

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

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

• uncertainties related to the legal and regulatory environment for our industry and our own legal proceedings and their outcome; and

• other factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the Securities and Exchange Commission.

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

3

Item 1. Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Share Data)

	June 30, 2013 (unaudited)			December 31, 2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	69,194		$	43,975
Accounts Receivable		28,012			24,980
Taxes Receivable		1,396			6,429
Short-Term Derivative Instruments		8,410			12,005
Assets Held for Sale		0			2,279
Inventory, Prepaid Expenses and Other		1,284			1,316
Total Current Assets		108,296			90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		598,731			485,448
Unevaluated Oil and Gas Properties		178,958			165,503
Other Property and Equipment		59,416			50,073
Wells and Facilities in Progress		104,751			92,913
Pipelines		6,958			6,116
Total Property and Equipment		948,814			800,053
Less: Accumulated Depreciation, Depletion and Amortization		(167,233	)		(146,038	)
Net Property and Equipment		781,581			654,015
Deferred Financing Costs and Other Assets – Net		12,625			10,029
Equity Method Investments		18,823			16,978
Long-Term Derivative Instruments		1,777			704
Total Assets	$	923,102		$	772,710
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	39,346		$	31,134
Accrued Expenses		36,802			22,421
Short-Term Derivative Instruments		1,554			1,389
Current Deferred Tax Liability		968			539
Liabilities Related to Assets Held for Sale		0			52
Total Current Liabilities		78,670			55,535
8.875% Senior Notes Due 2020		350,000			250,000
Premium (Discount) on Senior Notes – Net		3,245			(1,742	)
Senior Secured Line of Credit and Long-Term Debt		2,675			991
Long-Term Derivative Instruments		420			1,510
Long-Term Deferred Tax Liability		30,339			23,625
Other Deposits and Liabilities		5,472			5,675
Future Abandonment Cost		26,172			24,822
Total Liabilities	$	496,993		$	360,416
Commitments and Contingencies (See Note 13)
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 53,578,394 shares issued and outstanding on June 30, 2013 and 53,213,264 shares issued and outstanding on December 31, 2012.		52			52
Additional Paid-In Capital		453,127			451,062
Accumulated Deficit		(28,690	)		(39,595	)
Rex Energy Stockholders’ Equity		424,489			411,519
Noncontrolling Interests		1,620			775
Total Stockholders’ Equity		426,109			412,294
Total Liabilities and Stockholders’ Equity	$	923,102		$	772,710

See accompanying notes to the unaudited consolidated financial statements

4

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in Thousands, Except per Share Data)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	51,444		$	27,699		$	92,384		$	59,181
Field Services Revenue		3,840			2,514			10,345			4,820
Other Revenue		76			44			100			89
TOTAL OPERATING REVENUE		55,360			30,257			102,829			64,090
OPERATING EXPENSES
Production and Lease Operating Expense		13,092			10,972			26,492			23,272
General and Administrative Expense		7,782			5,774			15,578			11,185
Loss on Disposal of Assets		1,502			69			1,493			95
Impairment Expense		105			273			170			3,066
Exploration Expense		2,225			1,213			4,269			2,305
Depreciation, Depletion, Amortization and Accretion		12,943			10,623			24,101			20,167
Field Services Operating Expense		2,648			1,265			6,703			2,721
Other Operating Expense (Income)		447			(33	)		891			294
TOTAL OPERATING EXPENSES		40,744			30,156			79,697			63,105
INCOME FROM OPERATIONS		14,616			101			23,132			985
OTHER INCOME (EXPENSE)
Interest Expense		(5,826	)		(1,583	)		(9,831	)		(3,322	)
Gain on Derivatives, Net		11,741			3,642			3,201			11,081
Other Income		2,213			92,731			2,073			92,737
Loss on Equity Method Investments		(183	)		(3,430	)		(361	)		(3,564	)
TOTAL OTHER INCOME (EXPENSE)		7,945			91,360			(4,918	)		96,932
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		22,561			91,461			18,214			97,917
Income Tax Expense		(9,120	)		(35,268	)		(7,115	)		(37,899	)
INCOME FROM CONTINUING OPERATIONS		13,441			56,193			11,099			60,018
Income (Loss) From Discontinued Operations, Net of Income Taxes		520			(3,050	)		460			(8,405	)
NET INCOME		13,961			53,143			11,559			51,613
Net Income Attributable to Noncontrolling Interests		221			222			654			322
NET INCOME ATTRIBUTABLE TO REX ENERGY	$	13,740		$	52,921		$	10,905		$	51,291
Earnings per common share:
Basic – Net Income From Continuing Operations Attributable to Rex Common Shareholders	$	0.25		$	1.08		$	0.20		$	1.18
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders		0.01			(0.06	)		0.01			(0.16	)
Basic – Net Income Attributable to Rex Common Shareholders	$	0.26		$	1.02		$	0.21		$	1.02
Basic – Weighted Average Shares of Common Stock Outstanding		52,555			52,009			52,527			50,654
Diluted – Net Income From Continuing Operations Attributable to Rex Common Shareholders	$	0.25		$	1.06		$	0.20		$	1.16
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders		0.01			(0.06	)		0.01			(0.16	)
Diluted – Net Income Attributable to Rex Common Shareholders	$	0.26		$	1.00		$	0.21		$	1.00
Diluted – Weighted Average Shares of Common Stock Outstanding		52,911			52,876			52,901			51,567

See accompanying notes to the unaudited consolidated financial statements

5

REX ENERGY CORPORATION

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

FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 2013

(Unaudited, in Thousands)

	Common Stock
	Shares		Par Value		Additional Paid-In Capital			Accumulated Deficit			Rex Energy Stockholders’ Equity			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		2,316			0			2,316			0			2,316
Stock Option Exercises		27		0		266			0			266			0			266
Issuance of Restricted Stock, Net of Forfeitures		338		0		0			0			0			0			0
Capital Distributions		0		0		0			0			0			(406	)		(406	)
Change in Ownership of Noncontrolling Interests		0		0		(517	)		0			(517	)		597			80
Net Income		0		0		0			10,905			10,905			654			11,559
BALANCE June 30, 2013		53,578		52		453,127			(28,690	)		424,489			1,620			426,109

See accompanying notes to the unaudited consolidated financial statements

6

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	11,559		$	51,613
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		361			3,564
Non-Cash Expenses		3,027			749
Depreciation, Depletion, Amortization and Accretion		24,101			20,686
Unrealized (Gain) Loss on Derivatives		1,597			(2,000	)
Dry Hole Expense		485			562
Deferred Income Tax Expense		7,372			7,543
Impairment Expense		170			16,017
(Gain) Loss on Sale of Asset		524			(92,510	)
Changes in operating assets and liabilities
Accounts Receivable		1,974			1,289
Inventory, Prepaid Expenses and Other Assets		37			265
Accounts Payable and Accrued Expenses		10,353			9,671
Other Assets and Liabilities		(562	)		(824	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		60,998			16,625
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		107			215
Contributions to Equity Method Investments		(2,207	)		(3,552	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		3,732			122,651
Acquisitions of Undeveloped Acreage		(15,706	)		(33,331	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(123,609	)		(74,118	)
NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES		(137,683	)		11,865
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(876	)		(155,000	)
Proceeds from Long-Term Debt and Line of Credit		1,750			60,500
Repayments of Loans and Other Notes Payable		(786	)		(397	)
Proceeds from Senior Notes, Net of Discounts and Premiums		105,000			0
Debt Issuance Costs		(2,894	)		(98	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		0			(233	)
Proceeds from the Exercise of Stock Options		266			0
Distributions by the Partners of Consolidated Subsidiaries		(406	)		(58	)
Purchase of Noncontrolling Interests		(150	)		0
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			70,583
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		101,904			(24,703	)
NET INCREASE IN CASH		25,219			3,787
CASH – BEGINNING		43,975			11,796
CASH – ENDING	$	69,194		$	15,583
SUPPLEMENTAL DISCLOSURES
Interest Paid		15,337			2,960
Cash Paid for Income Taxes		57			270
NON-CASH ACTIVITIES
Increase in Accrued Capital Expenditures		13,399			5,167

See accompanying notes to the unaudited consolidated financial statements

7

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil, 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 and $0.6 million from Depreciation, Depletion, Amortization and Accretion to Interest Expense on our Consolidated Statement of Operations for the three and six months ended June 30, 2012, respectively, with no effect on previously reported net income, net income per share, accumulated deficit or stockholders’ equity. For the six months ended June 30, 2012, we reclassified approximately $3.9 million from changes in Other Assets and Liabilities to changes in Accounts Payable and Accrued Expenses with no effect to Cash Provided by Operating Activities.

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 Sheet as of December 31, 2012, 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.

8

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.

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 and six months ended June 30, 2013 and 2012 (in thousands):

	Exploration and Production		Field Services			Intercompany Eliminations			Consolidated Total
Three Months Ended June 30, 2013
Revenues	$	51,520		5,072			(1,232	)		55,360
Inter-Segment Revenues		0		(1,232	)		1,232			0
Total Revenues		51,520		3,840			0			55,360
Income (Loss) From Continuing Operations, Before Income Taxes	$	22,339		552			(330	)		22,561
Three Months Ended June 30, 2012
Revenues	$	27,743		3,342			(828	)		30,257
Inter-Segment Revenues		0		(828	)		828			0
Total Revenues		27,743		2,514			0			30,257
Income (Loss) From Continuing Operations, Before Income Taxes	$	90,548		1,141			(228	)		91,461
Six Months Ended June 30, 2013
Revenues	$	92,484		13,124			(2,779	)		102,829
Inter-Segment Revenues		0		(2,779	)		2,779			0
Total Revenues		92,484		10,345			0			102,829
Income (Loss) From Continuing Operations, Before Income Taxes	$	16,272		2,715			(773	)		18,214
Six Months Ended June 30, 2012
Revenues	$	59,270		5,841			(1,021	)		64,090
Inter-Segment Revenues		0		(1,021	)		1,021			0
Total Revenues		59,270		4,820			0			64,090
Income (Loss) From Continuing Operations, Before Income Taxes	$	96,451		1,739			(273	)		97,917
As of June 30, 2013
Total Assets	$	910,354		15,568			(2,820	)		923,102
As of December 31, 2012
Total Assets	$	766,599	$	12,166		$	(6,055	)	$	772,710

9

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 totaled approximately $0.5 million and $1.1 million for the three and six-month periods ended June 30, 2013, respectively, as compared to $0.5 million and $0.9 million for the three and six months ended June 30, 2012, 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	June 30, 2013
Beginning Balance at December 31, 2012	$	24,822
Future Abandonment Obligation Incurred		570
Future Abandonment Obligation Settled		(470	)
Future Abandonment Obligation Revision of Estimated Obligation		160
Future Abandonment Obligation Accretion Expense		1,090
Total Future Abandonment Cost	$	26,172

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. During the first quarter of 2013, we entered an 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. As of June 30, 2013, we have no continuing activities in the DJ Basin or continuing cash flows from this region.

Prior to their sale, these assets were classified as Assets Held for Sale on our Consolidated Balance Sheet at December 31, 2012. The results of operations are reflected in Discontinued Operations in our Consolidated Statements of Operations. We included $2.3 million of net assets located in the DJ Basin as Assets Held for Sale on our Consolidated Balance Sheet at December 31, 2012. We have included approximately $0.1 million of liabilities as Liabilities Related to Assets Held for Sale on our Consolidated Balance Sheet at December 31, 2012. These liabilities are primarily related to Accounts Payable and Accrued Expenses.

10

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

	Three Months Ended June 30,						Six Months Ended June 30,
($ in Thousands)	2013			2012			2013			2012
Revenues:
Oil and Gas Sales	$	16		$	22		$	25		$	51
Total Operating Revenue		16			22			25			51
Costs and Expenses:
Production and Lease Operating Expense		59			122			104			208
General and Administrative Expense		11			237			23			524
Exploration Expense		44			149			97			481
Impairment Expense		0			4,681			0			12,951
Depreciation, Depletion, Amortization and Accretion		0			0			0			0
Other Operating Expense (Income)		0			5			(3	)		8
(Gain) Loss on Sale of Asset		(973	)		0			(969	)		144
Total Expenses (Income)		(859	)		5,194			(748	)		14,316
Income (Loss) from Discontinued Operations Before Income Taxes		875			(5,172	)		773			(14,265	)
Income Tax (Expense) Benefit		(355	)		2,122			(313	)		5,860
Income (Loss) from Discontinued Operations, net of taxes	$	520		$	(3,050	)	$	460		$	(8,405	)
Production:
Crude Oil (Bbls)		209			311			356			655
Total (Mcfe)		1,254			1,866			2,136			3,930

5. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS

During the three and six months ended June 30, 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 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 six months ended June 30, 2013, approximately 92.8% of our commodity sales came from six purchasers, with the largest single purchaser accounting for 37.9% 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.

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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 currently $215.0 million. In connection with our offering of an additional 8.875% senior notes due 2020 in April 2013, 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.

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 June 30, 2013 and December 31, 2012, there were no outstanding amounts owed under 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 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 June 30, 2013 was 4.1 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

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interest coverage ratio as of June 30, 2013 was 5.8 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 June 30, 2013 was 3.3 to 1.0.

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 using the effective interest method. Interest is payable semi-annually at a rate of 8.875% per annum on June 1 and December 1 of each year, with the first interest payment made on June 1, 2013.

On April 26, 2013, we issued an additional $100.0 million in aggregate principal amount of the Senior Notes in a private offering at an issue price to the initial purchasers of 105% of par plus accrued interest from December 12, 2012. Net proceeds after discounts and offering expenses were approximately $102.8 million plus accrued interest of approximately $3.3 million. As of June 30, 2013, we had recorded on our Consolidated Balance Sheet approximately $353.2 million of Senior Notes, net of discounts and premiums.

We may redeem, at specified redemption prices, some or all of the Notes at any time on or after December 1, 2016. We may also redeem up to 35% of the 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, and any subsidiaries other than the subsidiary guarantors are minor. Rex Energy Corporation is a holding company with no independent assets or operations. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise.

In addition to the Senior Credit Facility and the 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 June 30, 2013 and December 31, 2012:

($ in Thousands)	June  30, 2013 (Unaudited)			December 31, 2012
8.875% Senior Notes Due 2020	$	350,000		$	250,000
Premium (Discount) on Senior Notes, Net		3,245			(1,742	)
Senior Line of Credit(a)		0			0
Capital Leases and Other Obligations(a)		5,080			2,677
Total Debts		358,325			250,935
Less Current Portion of Long-Term Debt(b)		(2,405	)		(1,686	)
Total Long-Term Debt	$	355,920		$	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. There were no amounts outstanding under the Senior Credit Facility as of June 30, 2013 and December 31, 2012. 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 and six months ended June 30, 2013 was approximately 2.8% and 3.0%, respectively.

^(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 June 30, 2013, our oil, NGL and natural gas derivative commodity instruments consisted of fixed rate swap contracts, collars, swaptions, puts, three-way collars and deferred put spreads. 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 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. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established. 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 $1.1 million and $5.3 million during the three-month periods ended June 30, 2013 and 2012, respectively, and $4.8 million and $9.1 million during the six-month periods ended June 30, 2013 and 2012, respectively, under these commodity derivative instruments. Unrealized gains and losses associated with our commodity derivative instruments amounted to a gain of $10.6 million and a loss of $1.6 million for the three and six months ended June 30, 2013, respectively, as compared to an unrealized loss of $1.7 million and an unrealized gain of $2.0 million for the three and six months ended June 30, 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 June 30, 2013 and 2012 ($ in thousands):

	Three Months Ended June 30, 2013									Three Months Ended June 30, 2012
	Realized			Unrealized						Realized			Unrealized
	Gains			Gains						Gains			Gains
	(Losses)			(Losses)			Total			(Losses)			(Losses)			Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	0		$	599		$	599		$	0		$	725		$	725
Mark-to-market fair value adjustments		0			1,018			1,018			0			5,187			5,187
Settlement of contracts(a)		(172	)		0			(172	)		(75	)		0			(75	)
Crude Oil Total		(172	)		1,617			1,445			(75	)		5,912			5,837
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0			(1,392	)		(1,392	)		0			(3,808	)		(3,808	)
Mark-to-market fair value adjustments		0			9,600			9,600			0			(4,902	)		(4,902	)
Settlement of contracts(a)		913			0			913			5,278			0			5,278
Natural Gas Total		913			8,208			9,121			5,278			(8,710	)		(3,432	)
Natural Gas Liquids
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0			(142	)		(142	)		0			0			0
Mark-to-market fair value adjustments		0			931			931			0			1,144			1,144
Settlement of contracts(a)		386			0			386			93			0			93
Natural Gas Liquids Total		386			789			1,175			93			1,144			1,237
Gain (Loss) on Derivatives, Net	$	1,127		$	10,614		$	11,741		$	5,296		$	(1,654	)	$	3,642

(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.

	Six Months Ended June 30, 2013									Six Months Ended June 30, 2012
	Realized			Unrealized						Realized			Unrealized
	Gains			Gains						Gains			Gains
	(Losses)			(Losses)			Total			(Losses)			(Losses)			Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	0		$	482		$	482		$	0		$	1,069		$	1,069
Mark-to-market fair value adjustments		0			382			382			0			2,490			2,490
Settlement of contracts(a)		(333	)		0			(333	)		(287	)		0			(287	)
Crude Oil Total		(333	)		864			531			(287	)		3,559			3,272
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0			(6,618	)		(6,618	)		0			(5,202	)		(5,202	)
Mark-to-market fair value adjustments		0			3,493			3,493			0			2,499			2,499
Settlement of contracts(a)		4,604			0			4,604			9,275			0			9,275
Natural Gas Total		4,604			(3,125	)		1,479			9,275			(2,703	)		6,572
Natural Gas Liquids
Reclassification of settled contracts included in prior periods mark-to-market adjustment		0			(268	)		(268	)		0			0			0
Mark-to-market fair value adjustments		0			932			932			0			1,144			1,144
Settlement of contracts(a)		527			0			527			93			0			93
Natural Gas Liquids Total		527			664			1,191			93			1,144			1,237
Gain (Loss) on Derivatives, Net	$	4,798			(1,597	)		3,201		$	9,081		$	2,000		$	11,081

(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 our Consolidated Balance Sheets as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net asset of approximately $8.2 million and a net asset of $9.8 million at June 30, 2013 and December 31, 2012, respectively.

As of June 30, 2013, we had approximately 94.7% and 71.4% of our current oil production on an annualized basis hedged through 2013 and 2014, respectively, approximately 95.5%, 79.2% and 17.6% of our current gas production on an annualized basis hedged through 2013, 2014 and 2015, respectively, and approximately 51.2% and 2.8% 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 June 30, 2013 consisted of:

Period	Volume		Put Option		Floor		Ceiling		Swap		Fair Market Value ($ in Thousands)
Oil
2013—Collar		30,000 Bbls	$	0	$	92.00	$	97.00	$	0	$	(5	)
2013—Swap		330,000 Bbls		0		0		0		93.35		(586	)
2013—Three Way Collar		30,000 Bbls		65.00		85.00		100.00		0		(17	)
2014—Three Way Collar		360,000 Bbls		69.00		84.18		104.27		0		423
2014—Collar		60,000 Bbls		0		90.00		97.65		0		200
2014—Deferred Put Spread		168,000 Bbls		75.00		90.00		0		0		(138	)
		978,000 Bbls									$	(123	)
Natural Gas
2013—Swap		4,920,000 Mcf	$	0	$	0	$	0	$	3.94	$	1,248
2013—Three Way Collar		1,260,000 Mcf		3.35		4.17		4.88		0		535
2013—Collar		780,000 Mcf		0		4.50		5.02		0		688
2013—Put		1,320,000 Mcf		0		5.00		0		0		1,537
2013—Swaption		600,000 Mcf		0		0		0		4.50		113
2013—Deferred Put Spread		900,000 Mcf		3.75		5.00		0		0		1,003
2014—Sold Call		1,800,000 Mcf		0		0		5.00		0		(168	)
2014—Three Way Collar		7,800,000 Mcf		3.13		4.02		4.68		0		1,424
2014—Swap		4,830,000 Mcf		0		0		0		3.97		359
2014—Collar		1,800,000 Mcf		0		3.51		4.43		0		(22	)
2015—Three Way Collar		2,400,000 Mcf		3.40		4.16		4.63		0		238
2015—Swap		1,200,000 Mcf		0		0		0		4.18		182
		29,610,000 Mcf									$	7,137
Natural Gas Liquids
2013—Swap		162,000 Bbls	$	0	$	0	$	0	$	57.48	$	1,135
2014—Swap		18,000 Bbls		0		0		0		47.46		64
		180,000 Bbls									$	1,199

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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 June 30, 2013 and December 31, 2012 is summarized below ($ in thousands):

	June 30,			December 31,
	2013			2012
Short-Term Derivative Assets:
Crude Oil—Collars	$	100		$	90
Crude Oil—Three Way Collars		212			0
Natural Gas Liquids—Swaps		1,199			535
Natural Gas—Swaps		2,286			2,416
Natural Gas—Swaption		113			354
Natural Gas—Three-Way Collars		1,267			1,021
Natural Gas—Deferred Put Spread		1,003			0
Natural Gas—Collars		693			4,211
Natural Gas—Puts		1,537			3,378
Total Short-Term Derivative Assets	$	8,410		$	12,005
Long-Term Derivative Assets:
Crude Oil—Collars	$	100		$	0
Crude Oil—Three Way Collar		211			0
Natural Gas—Swaps		501			239
Natural Gas—Collar		5			0
Natural Gas—Three Way Collar		960			465
Total Long-Term Derivative Assets	$	1,777		$	704
Total Derivative Assets	$	10,187		$	12,709
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(5	)	$	(307	)
Crude Oil—Swaps		(586	)		(217	)
Crude Oil—Three-Way Collars		(17	)		(45	)
Crude Oil—Deferred Put Spread		(69	)		0
Natural Gas—Three-Way Collars		(20	)		(35	)
Natural Gas—Collars		(16	)		0
Natural Gas—Sold Call		(84	)		0
Natural Gas—Swaps		(757	)		(785	)

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Total Short - Term Derivative Liabilities	$	(1,554	)	$	(1,389	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	0		$	(509	)
Crude Oil—Deferred Put Spread		(69	)		0
Natural Gas—Swaps		(241	)		(434	)
Natural Gas—Three-Way Collars		(10	)		(35	)
Natural Gas—Sold Call		(84	)		(366	)
Natural Gas—Collars		(16	)		(166	)
Total Long-Term Derivative Liabilities	$	(420	)	$	(1,510	)
Total Derivative Liabilities	$	(1,974	)	$	(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 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 and six months ended June 30, 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 June 30, 2013 Using:
	Total Carrying Value as of June 30, 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	$	8,213		0		8,213		0

(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, three-way collar, swap and deferred put spread 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 June 30, 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, three way collar and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”).

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The fair values attributable to our gas derivative contracts as of June 30, 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. The fair values attributable to our NGL derivative contracts as of June 30, 2013 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (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.

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:

$ in Thousands	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
8.875% Senior Notes due 2020	$	350,000		360,500	$	250,000	$	249,063
Capital Leases and Other Obligations		5,080		4,954		2,677		2,524
Total	$	355,080		365,454	$	252,677	$	251,587

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.

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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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Income Tax Expense	$	9,120		$	35,268		$	7,115		$	37,899
Effective Tax Rate		40.8	%		38.7	%		40.5	%		38.8	%

For the three and six months ended June 30, 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 and six months ended June 30, 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 and the reversal of certain valuation allowances that were related to deferred tax assets that we expect to realize.

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 June 30, 2013 and December 31, 2012, we had 53,578,394 and 53,213,264 shares of common stock outstanding, respectively. There were no shares of preferred stock outstanding as of June 30, 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 value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as 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 Amended and Restated 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our Board of Directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are: selecting participants to receive awards; determining the form, amount and other terms and conditions of awards; interpreting the provisions of the Plan or any award agreement; and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Internal Revenue Code or covered employees, may be structured to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.

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All awards granted under the Plan have been issued at the closing price of our common stock on the NASDAQ Global Select 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 Select Market on the date of grant. 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 and six months ended June 30, 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 and six months ended June 30, 2013 and 2012 was negligible. 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 six months ended June 30, 2013, was approximately $0.2 million. The total tax benefit for the six months ended June 30, 2013 was $0.1 million. There were no stock option exercises during the six months ended June 30, 2012.

A summary of the status of our issued and outstanding stock options as of June 30, 2013 is as follows:

	Outstanding				Exercisable
Exercise Price	Number Outstanding At 6/30/13		Weighted-Average Exercise Price		Number Exercisable At 6/30/13		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		169,833	$	9.99		169,833	$	9.99
$10.42		29,548	$	10.42		29,548	$	10.42
$11.87		3,500	$	11.87		2,334	$	11.87
$12.50		19,139	$	12.50		12,759	$	12.50
$13.01		18,526	$	13.01		12,351	$	13.01
$13.19		50,000	$	13.19		0	$	13.19
$19.92		5,000	$	19.92		5,000	$	19.92

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$22.34	30,000	$	22.34	30,000	$	22.34
$23.28	4,000	$	23.28	4,000	$	23.28
	475,587	$	11.00	411,866	$	10.68

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at June 30, 2013 were 4.3 years and $3.3 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at June 30, 2013 were 4.5 years and $3.0 million, respectively. As of June 30, 2013, unrecognized compensation expense related to stock options totaled approximately $0.2 million, which will be recognized over a weighted average period of 1.2 years.

Restricted Stock Awards

During the six-month period ended June 30, 2013, the Compensation Committee approved the issuance of an aggregate of 383,384 shares of restricted common stock to 40 employees and to 3 third-party contractors. During the six-month period ended June 30, 2012, the Compensation Committee approved the issuance of an aggregate of 63,996 shares of restricted stock to 17 employees. The shares granted are subject to time vesting and, in some cases, performance-based vesting. The performance shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the employees have been in continuous employment with us and third-party contractors have been able to provide services to 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 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 $1.1 million and $2.2 million for the three and six-month periods ended June 30, 2013, respectively, and $0.3 million and $0.8 million for the three and six-month periods ended June 30, 2012, respectively. As of June 30, 2013, total unrecognized compensation expense related to restricted common stock grants was approximately $5.1 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	%

The average fair value of the TSR awards as of December 31, 2012 and June 30, 2013 were $7.80 and $12.21 per share, respectively. Average fair values were estimated on the date of each 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:

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	Six Months Ended June 30, 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		33.6	%		54.4	%
Expected Volatility – Peer Group		31.4-59.3	%		31.2%-58.6	%
Market Index		36.3	%		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 six months ended June 30, 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		383,384		$	14.61
Forfeitures		(44,920	)	$	11.79
Vested		(158,219	)	$	11.66
Restricted stock awards, as of June 30, 2013		1,611,818		$	13.06

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

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circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

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

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 remain 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.

Environmental

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

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of June 30, 2013, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

At June 30, 2013, we had posted $1.0 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of June 30, 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 and six months ended June 30, 2013 was $0.2 million and $0.3 million, respectively, as compared to $0.1 million and $0.2 million, respectively, for the three and six months ended June 30, 2012. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):

2013	$	450
2014		842
2015		807
2016		815
2017		823
Thereafter		133
Total	$	3,870

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 $3.5 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 unused processing capacity with MarkWest were negligible during the three and six-month periods ended June 30, 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 $1.5 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 $4.2 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

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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.

For the three and six-month periods ended June 30, 2013 we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $5.1 million and $10.0 million, respectively, compared to the three and six-month periods ended June 30, 2012, of approximately $3.5 million and $6.3 million, respectively. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows ($ in thousands):

	Total
2013	$	1,890
2014		7,463
2015		16,525
2016		23,654
2017		29,495
Thereafter		326,367
Total	$	405,394

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 June 30, 2013, the remaining drilling carry obligation balance was approximately $9.3 million.

Under the terms of the agreement, 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. Should we not comply with the drilling commitments or terminate the agreement, we would be responsible for payment of any 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:

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	<$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, and paid, 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 are due on April 1 of each year. For the three and six months ended June 30, 2013 we recorded expenses of $0.7 million and $1.3 million, respectively, as compared to three and six months ended June 30, 2012, we recorded expenses of $0.6 million and $4.0 million, respectively, related to the Pennsylvania Impact Fee. We are recording the accrual of the impact fees as Production and Lease Operating Expense on our Consolidated Statements of Operations.

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 June 30, 2013 and December 31, 2012 and are included in Other Liabilities on our Consolidated Balance Sheets.

14. EARNINGS PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based vesting criteria. Diluted income per common share includes the assumed exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market based, given that the hypothetical effect is not anti-dilutive. Stock options to purchase 0.3 million shares of common stock for the three and six months ended June 30, 2013 were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of the common shares, which has an anti-dilutive effect on the computation. Performance-based restricted stock awards of 0.5 million shares and 0.6 million shares of common stock for the three and six months ended June 30, 2013, respectively, were outstanding but not included in the computations of diluted net income per share calculations due to performance metrics that have not yet been attained. Stock options to purchase 0.6 million shares of

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common stock for the three and six-month period ended June 30, 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 June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Numerator:
Net Income From Continuing Operations, Less Noncontrolling Interests	$	13,220	$	55,971		$	10,445	$	59,696
Net Income (Loss) From Discontinued Operations		520		(3,050	)		460		(8,405	)
Net Income	$	13,740	$	52,921		$	10,905	$	51,291
Denominator:
Weighted Average Common Shares Outstanding - Basic		52,555		52,009			52,527		50,654
Effect of Dilutive Securities:
Employee Stock Options		142		29			131		45
Employee Performance-Based Restricted Stock Awards		214		838			243		868
Weighted Average Common Shares Outstanding - Diluted		52,911		52,876			52,901		51,567
Earnings per Common Share:
Basic — Net Income From Continuing Operations	$	0.25	$	1.08		$	0.20	$	1.18
— Net Income (Loss) From Discontinued Operations		0.01		(0.06	)		0.01		(0.16	)
— Net Income	$	0.26	$	1.02		$	0.21	$	1.02
Diluted — Net Income From Continuing Operations	$	0.25	$	1.06		$	0.20	$	1.16
— Net Income (Loss) From Discontinued Operations		0.01		(0.06	)		0.01		(0.16	)
— Net Income	$	0.26	$	1.00		$	0.21	$	1.00

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

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development activities. The members of Water Solutions are Rex Energy Corporation and Sand Hills, owning 60% and 40% membership interests, respectively, after a change in membership interests which took effect on April 1, 2013. The change in membership interests occurred in accordance with the original operating agreement which stipulated that the change would occur upon the return of our initial capital investments. The change in ownership transaction, in which we retained our controlling financial interest, was accounted for as an equity transaction with no impact to our Consolidated Statement of Operations. Prior to the change in membership interests, the entity was owned 80% by us and 20% by Sand Hills.

We fully consolidate the accounts of Water Solutions in our Consolidated Financial Statements and account for the 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 $1.6 million was drawn as of June 30, 2013. There were no cash contributions during the first six months of 2013 and 2012. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of June 30, 2013 and December 31, 2012, with no restrictions or obligations to use certain assets to settle associated liabilities:

($ in Thousands)	As of June 30, 2013			As of December 31, 2012
Assets
Cash and Cash Equivalents	$	2,100		$	741
Accounts Receivable		3,528			3,360
Inventory, Prepaid Expenses and Other		24			13
Other Property and Equipment		5,849			3,560
Wells and Facilities in Progress		191			221
Accumulated Depreciation, Depletion and Amortization		(1,055	)		(501	)
Deferred Financing Costs and Other Assets—Net		170			199
Total Assets	$	10,807		$	7,593
Liabilities
Accounts Payable	$	1,822		$	1,554
Accrued Expenses		1,482			1,036
Senior Secured Line of Credit and Long-Term Debt		2,377			965
Total Liabilities	$	5,681		$	3,555

R.E. Disposal, LLC (formerly known as 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. During the second quarter of 2013, we purchased the remaining 49% membership interest owned by NorthStar for $0.2 million in cash and now own 100% of NorthStar #3, which was renamed R.E. Disposal, LLC. Upon NorthStar #3’s original formation, a note was issued from us to NorthStar #3 to assist in supplementing the operations. The note, which at the time of ownership change had a balance of $4.6 million, was terminated as a part of the change in ownership transaction. Prior to the change in ownership transaction, the financial results of NorthStar #3 were fully consolidated into our Consolidated Financial Statements while also eliminating any

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intercompany transactions, including the note payable due to us. The change in ownership transaction, in which we retained our controlling financial interest, was accounted for as equity transaction with no impact to our Consolidated Statements of Operations.

Prior to the change in ownership, we reported this entity as a variable interest entity. The carrying amount and classifications of R.E. Disposal, LLC (formerly NorthStar #3) assets and liabilities as of December 31, 2012 are as follows, with no restrictions or obligations to use certain assets to settle associated liabilities:

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

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 that facilitate development in our Appalachian Basin operations. We recorded our investment in RW Gathering of approximately $18.8 million and $16.8 million as of June 30, 2013 and December 31, 2012, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During the first six months of 2013, we contributed approximately $2.2 million in cash 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 six months of 2012. RW Gathering recorded net losses from continuing operations of $0.2 million and $0.2 million for the three and six months ended June 30, 2013, respectively, as compared to losses of $0.4 million and $0.8 million for the three and six months ended June 30, 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 our Consolidated Statements of Operations as Gain (Loss) on Equity Method Investments.

During the three and six-month periods ended June 30, 2013, we incurred approximately $0.2 million and $0.4 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC as compared to approximately $0.2 million and $0.5 million for the same periods in 2012. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of June 30, 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. We recognized a gain on the sale of our investment in Keystone Midstream of approximately $92.7 million during the second quarter of 2012. During the second quarter of 2013, we received approximately $2.3 million in proceeds related to the sale of Keystone Midstream which had previously been held in escrow.

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 six months ended June 30, 2012, we contributed approximately $2.1 million to Keystone Midstream primarily to support the construction of cryogenic gas processing plants. Keystone Midstream recorded net losses from operations of $11.6 million for the six month period ended June 30, 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

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For the three and six months ended June 30, 2013 we incurred approximately $0.1 million and $0.2 million in impairment expenses, respectively, as compared to $0.3 million and $3.1 million in impairment expenses for the three and six months ended June 30, 2012, 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 as of June 30, 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 June 30, 2013, we continued to carry the costs of undeveloped properties of approximately $179.0 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 and six months ended June 30, 2013 we incurred approximately $2.2 million and $4.3 million in exploration expenses, respectively, as compared to $1.2 million and $2.3 million in exploration expenses for the same periods ended June 30, 2012, respectively. Approximately $3.8 million of the expense incurred in 2013 was due to geological and geophysical type expenditures and delay rental payments. An additional $0.5 million was related to one exploratory well in Posey County, Indiana determined to be a dry hole. 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 was 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.

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

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2012 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

In June 2013, we sold our remaining DJ Basin asset holdings. Pursuant to the rules for discontinued operations, these assets have been classified as Assets Held for Sale on our historical 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.

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

Overview of Our Business

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

We divide our operations into two principal business segments, exploration and production and field services. We are headquartered in State College, Pennsylvania, and have regional offices in Bridgeport, Illinois; Cranberry, Pennsylvania; and Carrolton, Ohio.

2013 Activity

During the three and six months ended June 30, 2013, we produced 6,687.8 MMcfe and 12,316.7 MMcfe, respectively, in the Appalachian Basin. In the Illinois Basin, we produced 190.6 MBbls and 382.5 MBbls during the three and six months ended June 30, 2013, respectively. Overall, our production for the three and six months ended June 30, 2013 averaged 86,061 Mcfe and 80,726 Mcfe, respectively. As of June 30, 2013, we had 28.0 gross (16.9 net) wells drilled and awaiting completion. Our drilling and completion activity for the period indicated in each of our regions is set forth in the tables below.

For the three months ended June 30, 2013:

	Wells Drilled				Wells Completed				Wells Placed In Service
	Gross		Net		Gross		Net		Gross		Net
Appalachian Basin		13.0		8.5		7.0		5.5		10.0		7.5
Illinois Basin		5.0		5.0		8.0		8.0		8.0		8.0
Total		18.0		13.5		15.0		13.5		18.0		15.5

For the six months ended June 30, 2013:

	Wells Drilled				Wells Completed				Wells Placed In Service
	Gross		Net		Gross		Net		Gross		Net
Appalachian Basin		20.0		14.3		18.0		13.8		16.0		11.7
Illinois Basin		12.0		12.0		17.0		17.0		15.0		15.0
Total		32.0		26.3		35.0		30.8		31.0		26.7

Issuance of Additional Senior Notes

On April 26, 2013, we issued an additional $100.0 million aggregate principal amount of our 8.875% senior notes due 2020 at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional senior notes of approximately $102.8 million (after the initial purchasers’ premiums, commissions and offering expenses but excluding accrued interest of approximately $3.3 million) will be used to fund a portion of our 2013 capital expenditures and for general corporate purposes. These notes were issued as “additional notes” under the indenture governing our 8.875% Senior Notes due 2020 (collectively, the “Senior Notes”) and pursuant to which we had previously issued $250.0 million aggregate principal amount of Senior Notes due 2020 in December 2012, and under the indenture are treated as a single series with substantially identical terms as the Senior Notes previously issued. In connection with our April 2013 issuance of Senior Notes, we gave notice to the administrative agent under our credit agreement of our election to reduce the maximum commitments of the lenders under our Senior Credit Facility from $300.0 million to $215.0 million. See Item 1. Financial Statements—Note 8, “Long-Term Debt” for additional information on the Senior Notes.

Amended and Restated Revolving Credit Facility

        On March 27, 2013, we amended and restated our senior secured revolving credit agreement (as amended, the “credit agreement”). Initially, the borrowing base was $325.0 million; however, the maximum commitments of the lenders under our credit agreement were $300.0 million prior to our April 2013 offering of Senior Notes. Within the credit facility, a letter of credit subfacility exists for issuance of up to $25.0 million of letters of credit. Amounts borrowed may be repaid and reborrowed at any time prior to the maturity date, March 27, 2018. Certain of our wholly-owned subsidiaries jointly and severally guaranteed the prompt and complete payment of our obligations under our credit agreement. Our obligations under our credit agreement are secured by a security interest in substantially all of our assets.

The credit agreement provides that our borrowing base will be reduced by $0.25 for every dollar of certain new indebtedness; however, the lenders under our revolving credit facility waived this requirement in connection with our April 2013 offering of Senior Notes. Additionally, in connection with our April 2013 offering of Senior Notes, we gave notice to the administrative agent under our credit agreement of our election to reduce the maximum commitments of the lenders under our credit agreement from $300.0 million to $215.0 million. See Item 1. Financial Statements—Note 8, “Long-Term Debt” for additional information on our Senior Credit Facility and the Senior Notes.

Results of Continuing Operations

The following table sets forth summary information regarding oil, NGL and natural gas production and product prices for the three and six months ended June 30, 2013 and 2012.

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
Production:
Oil and Condensate (Bbls)		213,716		169,194		411,831		341,391

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Natural Gas (Mcf)		5,453,725	4,216,175		10,243,603	8,325,347
Natural Gas Liquids (Bbls)		182,541	76,465		316,209	139,960
Total (Mcfe)(a)		7,831,267	5,690,129		14,611,843	11,213,453
Average daily production:
Oil and Condensate (Bbls)		2,349	1,859		2,275	1,876
Natural Gas (Mcf)		59,931	46,332		56,594	45,774
Natural Gas Liquids (Bbls)		2,006	840		1,747	769
Total (Mcfe)(a)		86,061	62,529		80,726	61,614
Average sales price(b):
Oil and Condensate (per Bbl)	$	91.96	89.97	$	91.75	94.68
Natural Gas (per Mcf)	$	4.31	2.41	$	3.94	2.57
Natural Gas Liquids (per Bbl)	$	45.39	30.39	$	45.17	38.82
Total (per Mcfe)(a)		6.57	4.87	$	6.32	5.28
Average NYMEX prices(c):
Oil (per Bbl)	$	94.14	102.60	$	94.29	98.18
Natural Gas (per Mcf)	$	4.02	4.38	$	3.75	2.44

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

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

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

The following table sets forth summary information by basin regarding oil, NGL and natural gas revenues, production volumes, average product prices and average production costs for the three and six months ended June 30, 2013 and 2012.

	Production and Revenue by Basin
	For Three Months Ended June 30,				For Six Months Ended June 30,
	2013		2012		2013		2012
Appalachian
Revenue – Natural Gas(a)	$	23,504,589	$	10,152,435	$	40,315,117	$	21,425,303

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Volumes (Mcf)		5,453,725		4,216,175		10,243,603		8,325,347
Average Price	$	4.31	$	2.41	$	3.94	$	2.57
Revenue – Condensate(a)	$	2,005,825	$	51,075	$	2,528,977	$	101,592
Volumes (Bbl)		23,142		709		29,314		1,303
Average Price	$	86.67	$	72.04	$	86.27	$	77.97
Revenue – Natural Gas Liquids(a)	$	8,285,644	$	2,323,626	$	14,282,773	$	5,433,442
Volumes (Bbl)		182,541		76,465		316,209		139,960
Average Price	$	45.39	$	30.39	$	45.17	$	38.82
Average Production Cost per Mcfe(b)(c)	$	1.10	$	0.97	$	1.17	$	0.97
Illinois
Revenue – Oil(a)	$	17,647,835	$	15,171,369	$	35,257,012	$	32,221,081
Volumes (Bbl)		190,574		168,485		382,517		340,087
Average Price	$	92.60	$	90.05	$	92.17	$	94.74
Average Production Cost per Bbl(b)	$	29.02	$	33.31	$	30.75	$	30.81

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

(b) Excludes ad valorem and severance taxes.

(c) For the six months ended June 30, 2012, excludes the retroactive accrual of the Pennsylvania Impact Fee, which equates to $0.31 per Mcfe.

General Overview

Operating revenue for the three and six months ended June 30, 2013 increased 83.0% and 60.4%, respectively, when compared to the same period in 2012. The increase in operating revenue can be primarily attributed to higher production in both of our operating regions and increased commodity prices. In the Appalachian Basin, our production grew to 6,688 MMcfe for the three-month period ended June 30, 2013, from 4,679 MMcfe for the three-month period ended June 30, 2012, or approximately 42.9%, while realized natural gas prices have increased to $4.31 per Mcf from $2.41 per Mcf and NGL prices have increased to $45.39 per barrel from $30.39 per barrel over the same period in 2012. In the Illinois Basin, our production grew to 190.6 MBbls for the three-month period ended June 30, 2013 from 168.5 MBbls for the three-month period ended June 30, 2012, or approximately 13.1%. For the six months ended June 30, 2013, production in the Appalachian Basin has increased 34.3% to 12,317 MMcfe from the same period in 2012, while production in the Illinois Basin for the six months ended June 30, 2013 increased 12.5% to 382.5 MBls from the same period in 2012. Average commodity sales prices for the first half of 2013 increased 19.7% when compared to average commodity sales prices over the same period in 2012.

Operating expenses increased $10.6 million and $16.6 million for the three and six-month periods ended June 30, 2013, respectively, as compared to the same periods in 2012. Operating expenses primarily comprise: Production and Lease Operating Expenses, G&A Expenses, Gain/Loss on Disposal of Assets, Exploration Expenses, Impairment Expense, DD&A Expenses and Field Operating Expenses. The increases in operating expenses were largely attributable to Production and Lease Operating Expense, G&A Expense, DD&A Expenses and Field Service Operating Expenses. The increase of these operating expenses is consistent with our overall organizational growth as we continue to increase our drilling and exploration activity and our number of revenue generating assets.

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Comparison of the Three Months Ended June 30, 2013 to the Three Months Ended June 30, 2012.

Oil, NGL and natural gas revenue, including the effects of cash settled derivatives, for the three-month periods ended June 30, 2013 and 2012 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:

	For Three Months Ended June 30,
	2013			2012			Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	19,653		$	15,223		$	4,430			29.1	%
Oil derivatives realized(a)	$	(172	)	$	(75	)	$	(97	)		(129.3	%)
Total oil and condensate revenue and derivatives realized	$	19,481		$	15,148		$	4,333			28.6	%
Gas sales revenue	$	23,505		$	10,152		$	13,353			131.5	%
Gas derivatives realized(a)	$	913		$	5,278		$	(4,365	)		(82.7	%)
Total gas revenue and derivatives realized	$	24,418		$	15,430		$	8,988			58.3	%
Natural gas liquid revenue	$	8,286		$	2,324		$	5,962			256.5	%
Natural gas liquid derivatives realized(a)	$	386		$	93		$	293			N/M
Total natural gas liquid revenue	$	8,672		$	2,417		$	6,255			258.8	%
Consolidated sales	$	51,444		$	27,699		$	23,745			85.7	%
Consolidated derivatives realized(a)	$	1,127		$	5,296		$	(4,169	)		(78.7	%)
Total oil, NGL and gas revenue and derivatives realized	$	52,571		$	32,995		$	19,576			59.3	%
Total Mcfe Production		7,831,267			5,690,129			2,141,138			37.6	%
Average Realized Price per Mcfe	$	6.71		$	5.80		$	0.91			15.7	%

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

Average realized price received for oil, NGLs and natural gas during the second quarter of 2013, after the effect of derivative activities, was $6.71 per Mcfe, an increase of 15.7%, or $0.91 per Mcfe, from the same quarter in 2012. This increase was primarily due to an upward trend of average realized commodity prices, which was partially offset by a decrease in realized derivative settlements. The average price for natural gas, after the effect of derivative activities, increased 22.4%, or $0.82 per Mcf, to $4.48 per Mcf. The average price for oil and condensate, after the effect of derivative activities, increased 1.8%, or $1.62 per barrel, to $91.15 per barrel. The average price for NGLs, after the effect of derivative activities, increased 50.3%, or $15.90 per barrel, to $47.51 per barrel. Our derivative activities effectively increased net realized price by $0.14 per Mcfe in the second quarter of 2013 and $0.93 per Mcfe in the second quarter of 2012.

Production volumes in the second quarter of 2013 increased 37.6% from the second quarter of 2012. Natural gas production increased approximately 29.4%, oil production increased approximately 26.3% and NGL production increased approximately 138.7%. Our production continues to be positively impacted by strong drilling results in both the Appalachian Basin and the Illinois Basin.

Overall, our production for the three months ended June 30, 2013 averaged 86,061 Mcfe per day, of which 69.6% was attributable to natural gas, 16.4% to oil and 14.0% to NGL production.

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Statements of Operations for the three-month periods ended June 30, 2013 and 2012 are as follows:

	For Three Months Ended June 30,
	2013			2012			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	51,444		$	27,699			23,745			85.7	%
Field Services Revenue		3,840			2,514			1,326			52.7	%
Other Revenue		76			44			32			72.7	%
TOTAL OPERATING REVENUE		55,360			30,257			25,103			83.0	%
OPERATING EXPENSES
Production and Lease Operating Expense		13,092			10,972			2,120			19.3	%
General and Administrative Expense		7,782			5,774			2,008			34.8	%
Loss on Disposal of Asset		1,502			69			1,433			N/M
Impairment Expense		105			273			(168	)		(61.5	%)
Exploration Expense		2,225			1,213			1,012			83.4	%
Depreciation, Depletion, Amortization and Accretion		12,943			10,623			2,320			21.8	%
Field Service Operating Expense		2,648			1,265			1,383			109.3	%
Other Operating Expense (Income)		447			(33	)		480			N/M
TOTAL OPERATING EXPENSES		40,744			30,156			10,588			35.1	%
INCOME FROM OPERATIONS		14,616			101			14,515			N/M
OTHER INCOME (EXPENSE)
Interest Expense		(5,826	)		(1,583	)		(4,243	)		(268.0	%)
Gain on Derivatives, Net		11,741			3,642			8,099			222.4	%
Other Income		2,213			92,731			(90,518	)		(97.6	%)
Loss on Equity Method Investments		(183	)		(3,430	)		3,247			94.7	%
TOTAL OTHER INCOME		7,945			91,360			(83,415	)		(91.3	%)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		22,561			91,461			(68,900	)		(75.3	%)
Income Tax Expense		(9,120	)		(35,268	)		26,148			74.1	%
INCOME FROM CONTINUING OPERATIONS		13,441			56,193			(42,752	)		(76.1	%)
Income (Loss) From Discontinued Operations, Net of Income Taxes		520			(3,050	)		3,570			117.0	%
NET INCOME		13,961			53,143			(39,182	)		(73.7	%)
Net Income Attributable to Noncontrolling Interests		221			222			(1	)		(0.5	%)
NET INCOME ATTRIBUTABLE TO REX ENERGY	$	13,740		$	52,921			(39,181	)		(74.0	%)

Field Services Revenue for the three months ended June 30, 2013 increased approximately $1.3 million from the second quarter of 2012. We generate field services revenue from various field service activities such as the management of water sourcing, water transfer and water disposal activities in the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays have led to the growth of our field services activities, particularly water transfer to service well completion activities.

Production and Lease Operating Expense increased approximately $2.1 million, or 19.3%, in the second quarter of 2013 from the same period in 2012. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin as they relate to variable type costs such as transportation, marketing, processing and gathering. Since March 31, 2012, we have entered into several new transportation and marketing agreements to enhance our ability to sell our natural gas and NGLs. For the second quarter of 2013, these transportation and marketing agreements accounted for approximately 39.6% of our total Production and Lease Operating Expense as compared to 32.3% in the second quarter of 2012. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Additionally, the Commonwealth of Pennsylvania instituted the Pennsylvania Impact Fee during the first quarter of 2012, which compounds each year as new wells are spud.

G&A Expense for the second quarter of 2013 increased approximately $2.0 million, or 34.8%, to $7.8 million from the same period in 2012. The year-over-year increase is predominately due to the expansion of our Appalachian Basin operations and our corporate headquarters and is commensurate with our overall organizational growth.

Impairment Expense for the second quarter of 2013 and 2012 totaled approximately $0.1 million and $0.3 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the second quarter of 2013 and 2012 is primarily related to acreage in Pennsylvania that is not contiguous with our existing development area. These leases are approaching expiration, and we have no current plans to extend the leases or develop this acreage. As of June 30, 2013, we continued to carry the costs of undeveloped properties of approximately $179.0 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.

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Exploration Expensefor the three months ended June 30, 2013 was approximately $2.2 million as compared to $1.2 million for the three months ended June 30, 2012. Approximately $1.3 million of expense incurred in second quarter 2013 was due to geological and geophysical type expenditures and delay rental payments associated with leases in the Appalachian Basin and $0.9 million due to geological and geophysical type expenditures and dry hole expense in the Illinois Basin. Approximately $1.2 million of the expense incurred in second quarter 2012 was due to geological and geophysical type expenditures and delay rental payments primarily associated with leases in the Appalachian Basin.

DD&A Expenses for the three months ended June 30, 2013 increased approximately $2.3 million, or 21.8%, from $10.6 million for the same period in 2012. The period-over-period increase in DD&A expense is consistent with the growth in our asset base, reserves and production since the comparable period of 2012.

Field Service Operating Expense for the second quarter of 2013 totaled approximately $2.6 million as compared to $1.3 million for the same period in 2012. Our field services operating expenses are largely variable in nature and fluctuate commensurate with our level of activity. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, particularly those associated with water transfer for well completion operations.

Interest Expense for the three months ended June 30, 2013 was approximately $5.8 million as compared to $1.6 million during the second quarter of 2012. The increase in interest expense was due to our issuance of $250.0 million of Senior Notes in December 2012 and issuance of additional $100.0 million of Senior Notes in April 2013. We expect our interest expense to remain higher than in the prior year period as a result of our issuance of the Senior Notes.

Gain on Derivatives, Net was approximately $11.7 million for the second quarter of 2013 as compared to $3.6 million for the same period in 2012. Changes were attributable to the volatility of oil, NGL and gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil, NGL and gas production volumes given the highly volatile oil, NGL and gas commodities market.

Other Income for the second quarter of 2013 was approximately $2.2 million as compared to $92.7 million in the second quarter of 2012. During the second quarter of 2012, we sold our investment in Keystone Midstream Services, LLC, for which we received net proceeds of $121.4 million and recognized a gain of approximately $92.7 million. During the second quarter of 2013, we received payment of approximately $2.3 million representing amounts that were being held in escrow related to the sale of our investment in Keystone Midstream Services, LLC.

Net Income Tax Expense was approximately $9.1 million for the three months ended June 30, 2013 as compared to $35.3 million for the three months ended June 30, 2012. The change was primarily due to the tax effect of the gain on the sale of our investment in Keystone Midstream Services, LLC during the second quarter of 2012. The effective tax rate for the second quarter of 2013 was relatively comparable to the effective tax rate in the second quarter of 2012.

Net Income Attributable to Rex Energy for the second quarter of 2013 was approximately $13.7 million, as compared to $52.9 million for the comparable period in 2012 as a result of the factors discussed above.

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Comparison of the Six Months Ended June 30, 2013 to the Six Months Ended June 30, 2012.

Oil, NGL and natural gas revenue, including the effects of cash settled derivatives, for the six-month periods ended June 30, 2013 and 2012 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:

	For Six Months Ended June 30,
	2013			2012			Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	37,786		$	32,323		$	5,463			16.9	%
Oil derivatives realized(a)	$	(333	)	$	(286	)	$	(47	)		(16.4	%)
Total oil and condensate revenue and derivatives realized	$	37,453		$	32,037		$	5,416			16.9	%
Gas sales revenue	$	40,315		$	21,425		$	18,890			88.2	%
Gas derivatives realized(a)	$	4,604		$	9,275		$	(4,671	)		(50.4	%)
Total gas revenue and derivatives realized	$	44,919		$	30,700		$	14,219			46.3	%
Natural gas liquid revenue	$	14,283		$	5,433		$	8,850			162.9	%
Natural gas liquid derivatives realized(a)	$	527		$	93		$	434			N/M
Total natural gas liquid revenue	$	14,810		$	5,526		$	9,284			168.0	%
Consolidated sales	$	92,384		$	59,181		$	33,203			56.1	%
Consolidated derivatives realized(a)	$	4,798		$	9,082		$	(4,284	)		(47.2	%)
Total oil, NGL and gas revenue and derivatives realized	$	97,182		$	68,263		$	28,919			42.4	%
Total Mcfe Production		14,611,843			11,213,453			3,398,390			30.3	%
Average Realized Price per Mcfe	$	6.65		$	6.09		$	0.56			9.2	%

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

Average realized price received for oil, NGLs and natural gas during the first six months of 2013, after the effect of derivative activities, was $6.65 per Mcfe, an increase of 9.2%, or $0.56 per Mcfe, from the same period in 2012. This increase was primarily due to an upward trend of average realized natural gas and NGL prices, which was partially offset by a decrease in realized derivative settlements. The average price for natural gas, after the effect of derivative activities, increased 19.0%, or $0.70 per Mcf, to $4.39 per Mcf. The average price for oil and condensate, after the effect of derivative activities, decreased 3.1%, or $2.90 per barrel, to $90.94 per barrel. The average price for NGLs, after the effect of derivative activities, increased 18.6%, or $7.35 per barrel, to $46.84 per barrel. Our derivative activities effectively increased net realized price by $0.33 per Mcfe in the first half of 2013 and $0.81 per Mcfe in the first half of 2012.

Production volumes in the first six months of 2013 increased 30.3% from the same period in 2012. Natural gas production increased approximately 23.0%, oil production increased approximately 20.6% and NGL production increased approximately 125.9%. Our production continues to be positively impacted by strong drilling results in both the Appalachian Basin and the Illinois Basin.

Overall, our production for the six months ended June 30, 2013 averaged 80,726 Mcfe per day, of which 70.1% was attributable to natural gas, 16.9% to oil and 13.0% to NGL production.

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Statements of Operations for the six-month periods ended June 30, 2013 and 2012 are as follows:

	For Six Months Ended June 30,
	2013			2012			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	92,384		$	59,181			33,203			56.1	%
Field Services Revenue		10,345			4,820			5,525			114.6	%
Other Revenue		100			89			11			12.4	%
TOTAL OPERATING REVENUE		102,829			64,090			38,739			60.4	%
OPERATING EXPENSES
Production and Lease Operating Expense		26,492			23,272			3,220			13.8	%
General and Administrative Expense		15,578			11,185			4,393			39.3	%
Loss on Disposal of Asset		1,493			95			1,398			N/M
Impairment Expense		170			3,066			(2,896	)		(94.5	%)
Exploration Expense		4,269			2,305			1,964			85.2	%
Depreciation, Depletion, Amortization and Accretion		24,101			20,167			3,934			19.5	%
Field Service Operating Expense		6,703			2,721			3,982			146.3	%
Other Operating Expense		891			294			597			203.1	%
TOTAL OPERATING EXPENSES		79,697			63,105			16,592			26.3	%
INCOME FROM OPERATIONS		23,132			985			22,147			N/M
OTHER INCOME (EXPENSE)
Interest Expense		(9,831	)		(3,322	)		(6,509	)		(195.9	%)
Gain on Derivatives, Net		3,201			11,081			(7,880	)		(71.1	%)
Other Income		2,073			92,737			(90,664	)		(97.8	%)
Loss on Equity Method Investments		(361	)		(3,564	)		3,203			89.9	%
TOTAL OTHER INCOME (EXPENSE)		(4,918	)		96,932			(101,850	)		(105.1	%)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		18,214			97,917			(79,703	)		(81.4	%)
Income Tax Expense		(7,115	)		(37,899	)		30,784			81.2	%
INCOME FROM CONTINUING OPERATIONS		11,099			60,018			(48,919	)		(81.5	%)
Income (Loss) From Discontinued Operations, Net of Income Taxes		460			(8,405	)		8,865			105.5	%
NET INCOME		11,559			51,613			(40,054	)		(77.6	%)
Net Income Attributable to Noncontrolling Interests		654			322			332			103.1	%
NET INCOME ATTRIBUTABLE TO REX ENERGY	$	10,905		$	51,291			(40,386	)		(78.7	%)

Field Services Revenue for the six months ended June 30, 2013 and 2012 was approximately $10.3 million and $4.8 million, respectively. We generate field services revenue from various field service activities such as the management of water sourcing, water transfer and water disposal activities in the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays have led to the growth of our field services activities, particularly water transfer to service well completion activities.

Production and Lease Operating Expenses increased approximately $3.2 million, or 13.8%, in the first half of 2013 from the same period in 2012. Since March 31, 2012, we have entered into several new transportation and marketing agreements to enhance our ability to sell our natural gas and NGLs. For the six months ended June 30, 2013, these transportation and marketing agreements accounted for approximately 38.2% of our Production and Lease Operating Expense as compared to 27.3% for the same period in 2012. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Additionally, the Commonwealth of Pennsylvania instituted the Pennsylvania Impact Fee during the first quarter of 2012, which compounds each year as new wells are spud.

G&A Expenses for the first half of 2013 increased approximately $4.4 million, or 39.3%, to $15.6 million from the same period in 2012. The year-over-year increase is predominately due to the expansion of our Appalachian Basin operations and our corporate headquarters and is commensurate with our overall organizational growth.

Impairment Expenses for the first half of 2013 and 2012 totaled approximately $0.2 million and $3.1 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expenses incurred during both periods are primarily related to acreage in Pennsylvania that is not contiguous with our existing development area. These leases are approaching expiration, and we currently have no plans to extend the leases or develop this acreage. As of June 30, 2013, we continued to carry the costs of undeveloped properties of

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approximately $179.0 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.

Exploration Expensefor the first half of 2013 was approximately $4.3 million, as compared to $2.3 million for the same period during 2012. Approximately $2.7 million of expense incurred in the first half of 2013 was due to geological and geophysical type expenditures and delay rental payments associated with leases in the Appalachian Basin and $1.6 million due to geological and geophysical type expenditures and dry hole expense in the Illinois Basin. Approximately $2.0 million of the expense incurred in 2012 was due to geological and geophysical expenditures and delay rental payments primarily associated with leases in the Appalachian Basin. The remaining $0.3 million spent during the first half of 2012 is related to the plugging of two exploratory Marcellus Shale wells that were spud during 2011 in Butler County, Pennsylvania. Minimal drilling was completed on these wells before a strategic decision was made to abandon the well locations and reallocate the remaining capital to other leases that will enable us to hold additional acreage by production.

DD&A Expenses for the first half of 2013 increased to approximately $24.1 million, an increase of 19.5%, from $20.2 million for the same period in 2012. The period over period increase in DD&A Expenses is consistent with the growth in our asset base, reserves and production since the comparable period in 2012.

Field Services Operating Expense for the six months ended June 30, 2013 and 2012 was approximately $6.7 million and $2.7 million, respectively. Our field services operating expenses are largely variable in nature and fluctuate commensurate with our level of activity. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, particularly those associated with water transfer to serve well completion activities.

Interest Expense for the first half of 2013 was approximately $9.8 million, as compared to $3.3 million during the first half of 2012. The increase in interest expense was due to our issuance of $250.0 million of Senior Notes in December 2012 and issuance of additional $100.0 million of Senior Notes in April 2013, which carries a higher interest rate compared to amounts outstanding under our Senior Credit Facility as of June 30, 2012. We expect our interest expense to remain higher than the prior year period as a result of our issuance of the Senior Notes.

Gain on Derivatives, Net was approximately $3.2 million for the first half of 2013 as compared to $11.1 million for the same period in 2012. Changes were attributable to the volatility of oil and gas commodity prices along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other Income for the six months ended June 30, 2013 and 2012 totaled approximately $2.1 million and $92.7 million, respectively. During the second quarter of 2012, we sold our investment in Keystone Midstream Services, LLC, for which we received net proceeds of $121.4 million and recognized a gain of approximately $92.7 million. During the second quarter of 2013, we received payment of approximately $2.3 million representing amounts that were being held in escrow related to the sale of our investment in Keystone Midstream Services, LLC.

Income Tax Expense was approximately $7.1 million for the six months ended June 30, 2013 as compared to $37.9 million for the six months ended June 30, 2012. The change was primarily due to the tax effect of the gain on the sale of our investment in Keystone Midstream during the second quarter of 2012. The effective tax rate for the first six months of 2013 was relatively comparable to the effective tax rate in the first six months of 2012.

Net Income Attributable to Rex Energy for the first half of 2013 was approximately $10.9 million, as compared to $51.3 million for the comparable period in 2012 as a result of the factors discussed above.

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	Other Performance Measurements From Continuing Operations
	For Three Months Ended June 30,				For Six Months Ended June 30,
	2013		2012		2013		2012
EBITDAX (in thousands)(a)	$	33,265	$	17,959	$	59,346	$	39,513
LOE per Mcfe(b)	$	1.67	$	1.93	$	1.81	$	1.82
G&A per Mcfe	$	0.99	$	1.01	$	1.07	$	1.00

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

(b) For six months ended June 30, 2012, excludes retroactive accrual of Pennsylvania Impact Fee, which equates to approximately $0.25 per Mcfe on a company-wide basis.

EBITDAX (Non-GAAP)

EBITDAX (Non-GAAP) from continuing operations increased approximately $15.3 million to $33.3 million for the three-month period ended June 30, 2013 as compared to the same period in 2012. EBITDAX from continuing operations increased approximately $19.8 million to $59.3 million for the six-month period ended June 30, 2013 as compared to the same period in 2012. The increases in EBITDAX can be primarily attributed to higher production and higher average sales prices for natural gas, resulting in increased operating revenues. These increases were partially offset by an increase in operating expenses. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

LOE per Mcfe

LOE per Mcfe measures the average cost of extracting oil, NGLs and natural gas from our basin reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our oil, NGL and natural gas reserves in the ground. LOE per Mcfe decreased to $1.67 for the three months ended June 30, 2013 as compared to $1.93 for the same period in 2012. LOE per Mcfe decreased to $1.81 for the six months ended June 30, 2013 as compared to $1.82 for the same period in 2012. For comparative purposes, we have excluded approximately $0.25 per Mcfe from the calculation of our first half of 2012 lifting cost which represents the retroactive portion of the Pennsylvania impact fee for wells spud prior to 2012. Since the first half of 2012 we have entered into several new transportation and marketing agreements to protect the ability to sell our natural gas and NGLs. During the three and six months ended June 30, 2013, these transportation and marketing agreements accounted for approximately 39.6% and 38.2%, respectively, of our lifting cost as compared to 32.3% and 27.3% for the same periods in 2012. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. As we continue to grow our operations, particularly those in the Appalachian Basin, which have lower operating costs, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

G&A Expenses per Mcfe

Our general and administrative expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe decreased to approximately $0.99 for the three-month period ended June 30, 2013 as compared to $1.01 for the same period in 2012. G&A expenses per Mcfe increased to approximately $1.07 for the six-month period ended June 30, 2013 as compared to $1.00 for the same period in 2012. The increase for the six month period ended June 30, 2013 is predominately due to the expansion of our Appalachian Basin operations and our corporate headquarters that is commensurate with our overall organizational growth.

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Capital Resources and Liquidity

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the six months ended June 30, 2013, we spent $139.3 million in cash on drilling projects, facilities and related equipment and acquisitions of unproved acreage. Our total budget for 2013, excluding the acquisition of unproved acreage, is $250.0 to $275.0 million. We funded our capital program with net cash flows from operations and net proceeds from our issuance of $350.0 million aggregate principal amount of Senior Notes. The remainder of our 2013 capital budget is expected to be funded primarily by cash flow from operations, non-core assets sales, proceeds from our Senior Notes and borrowings under our Senior Credit Facility. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a significant drop in commodity prices, particularly natural gas, or reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may also elect to issue additional shares of stock, subordinated notes or other securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

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

Our cash flows from operations are driven by commodity prices and production volumes. Prices for oil, NGLs and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, cash flows from operations, borrowings from our Senior Credit Facility and net proceeds from debt and equity offerings have been primarily used to fund exploration and development of our oil and gas interests.

As of June 30, 2013, we had a $325.0 million borrowing base under our Senior Credit Facility with maximum lender commitments of $215.0 million. We are not restricted as to our borrowings under the Senior Credit Facility; however we are subject to the minimum financial requirements detailed in Note 8,Long-Term Debt, to our Consolidated Financial Statements.

Future Liquidity Considerations

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay fees in connection with these agreements of $79.0 million over the next five years, depending on our levels of production. Also in connection with certain of these agreements, we have guaranteed the payment of obligations up to a maximum of $406.4 million over the life of the agreements.

Financial Condition and Cash Flows for the Six Months Ended June 30, 2013 and 2012

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

	Six Months Ended June 30, ($ in Thousands)
	2013			2012
Cash flows provided by operating activities	$	60,998		$	16,625
Cash flows (used in) provided by investing activities		(137,683	)		11,865
Cash flows provided by (used in) financing activities		101,904			(24,703	)
Net increase in cash and cash equivalents	$	25,219		$	3,787

Net cash provided by operating activities increased by approximately $44.4 million in the first six months of 2013 over the same period in 2012. The increase in 2013 was primarily driven by our higher operating revenue as a result of our continued success in the Appalachian and Illinois Basin in addition to timing differences on our Accounts Payable and Accrued Expense. These increases were partially offset by higher operating expenses, particularly Production and Lease Operating Expense, G&A Expense and Field Services Operating Expense.

Net cash (used in) provided by investing activities decreased from cash provided by investing activities of approximately $11.9 million from the first six months of 2012 to cash used by investing activities of $137.7 million in the first six months of 2013. This change can be primarily attributed to the net proceeds of our interest in Keystone Midstream Services, LLC of approximately $121.4 million during the second quarter of 2012 and expanded exploration and development activity in Ohio and the Illinois Basin during the first six months of 2013.

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Net cash provided by (used in) financing activities increased to cash provided by financing activities of approximately $101.9 million for the first six months of 2013 from cash used by financing activities of approximately $24.7 million for the first six months of 2012. The change is primarily due to our offering of additional Senior Notes during the second quarter of 2013, for which we received proceeds of $105.0 million, in addition to net repayments of debt during 2012 of approximately $94.9 million, which was partially offset by proceeds we received from our public offering of common stock during the first quarter of 2012, for which we received net proceeds of approximately $70.6 million.

Effects of Inflation and Changes in Price

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

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended June 30, 2013, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2012. We describe critical recently adopted and issued accounting standards in Item 1. Financial Statements—Note 6, “Recently Issued Accounting Pronouncements.”

Non-GAAP Financial Measures

EBITDAX

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

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

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

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

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

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

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

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

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Net Income From Continuing Operations	$	13,441		$	56,193		$	11,099		$	60,018
Net Income Attributable to Noncontrolling Interests		(221	)		(222	)		(654	)		(322	)
Income From Continuing Operations Attributable to Rex Energy		13,220			55,971			10,445			59,696
Add Back Non-Recurring Losses(a)		—			—			—			2,809
Add Back Depletion, Depreciation, Amortization and Accretion		12,943			10,884			24,101			20,686
Add Back Non-Cash Compensation Expense		1,160			362			2,423			841
Add Back Interest Expense		5,826			1,322			9,831			2,803
Add Back Impairment Expense		105			273			170			3,066
Add Back Exploration Expenses		2,225			1,213			4,269			2,305
Less Gain on Disposal of Assets(b)		(751	)		(92,679	)		(760	)		(92,653	)
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives		(10,614	)		1,654			1,597			(2,000	)
Less Non-Cash Portion of Noncontrolling Interests		(152	)		(18	)		(206	)		(60	)
Add Back Income Tax Expense		9,120			35,268			7,115			37,899
Add Back Non-Cash Portion of Equity Method Investments		183			3,709			361			4,121
EBITDAX From Continuing Operations	$	33,265		$	17,959		$	59,346		$	39,513
Net Income (Loss) From Discontinued Operations	$	520		$	(3,050	)	$	460		$	(8,405	)
Add Back Non-Cash Compensation Expense		—			2			—			12
Add Back Impairment Expense		—			4,681			—			12,951
Add Back Exploration Expenses		44			149			97			481
Add Back (Less) Loss (Gain) on Disposal of Assets		(973	)		—			(969	)		144
Add Back (Less) Income Tax Expense (Benefit)		355			(2,123	)		313			(5,860	)
Add EBITDAX From Discontinued Operations	$	(54	)	$	(341	)	$	(99	)	$	(677	)
EBITDAX (Non-GAAP)	$	33,211		$	17,618		$	59,247		$	38,836

^(a)  Includes $2.8 million related to the retroactive portion of the Pennsylvania Impact Fee for the six months ended June 30, 2012.

^(b)  Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million for the three and six months ended June 30, 2012, and $2.3 million for the three and six months ended June 30, 2013.

Volatility of Oil, NGL and Natural Gas Prices

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

For the three and six months ended June 30, 2013, the net realized gains on oil, NGL and natural gas derivatives were approximately $1.1 million and $4.8 million, respectively, as compared to net realized gains of approximately $5.3 million and $9.1 million for the comparable periods in 2012, respectively. These gains are reported as Gain on Derivatives, Net in our Consolidated Statements of Operations. As of June 30, 2013, we had approximately 94.7% and 71.4% of our current oil production on an annualized basis hedged through 2013 and 2014, respectively, 95.5%, 79.2% and 17.6% of our current natural gas production on an annualized basis hedged through 2013, 2014 and 2015, respectively, and approximately 51.2% and 2.8% of our current NGL production on an annualized basis hedged through 2013 and 2014, respectively.

For the three and six months ended June 30, 2013, the net unrealized settlements on oil, NGL and natural gas derivatives were a gain of $10.6 million and a loss of $1.6 million, respectively, as compared to a loss of $1.6 million and a gain of $2.0 million for the comparable periods in 2012, respectively. The net unrealized gains and losses are reported as Gain on Derivatives, Net in our Consolidated Statements of Operations.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil, NGLs and natural gas. We enter into all of our derivatives transactions with two

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

For a summary of our current oil, NGL and natural gas derivative positions at June 30, 2013, refer to Note 9 of our Consolidated Financial Statements, Fair Value of Financial and Derivative Instruments.

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Item 3. Quantitative And Qualitative Disclosures About Market Risk.

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, NGLs and natural gas. Conversely, increases in the market prices for oil, NGLs and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on production through June 30, 2013, we project that a 10% decline in the price per barrel of oil and NGLs and the price per Mcf of gas from the first six months of the 2013 average would reduce our gross revenues, before the effects of derivatives, for the remaining six months of 2013 by approximately $9.2 million.

We have designed our hedging program to reduce the risk of price volatility for our production in the oil, NGL and natural gas markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps, collars, put spreads, put options, swaptions and three way collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in oil, NGL and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil, NGLs and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

At June 30, 2013, we had the following commodity derivative contracts outstanding:

Period	Volume		Put Option		Floor		Ceiling		Swap		Fair Market Value ($ in Thousands)
Oil
2013—Collar		30,000 Bbls	$	0	$	92.00	$	97.00	$	0	$	(5	)
2013—Swap		330,000 Bbls		0		0		0		93.35		(586	)
2013—Three Way Collar		30,000 Bbls		65.00		85.00		100.00		0		(17	)
2014—Three Way Collar		360,000 Bbls		69.00		84.18		104.27		0		423
2014—Collar		60,000 Bbls		0		90.00		97.65		0		200
2014—Deferred Put Spread		168,000 Bbls		75.00		90.00		0		0		(138	)
		978,000 Bbls									$	(123	)
Natural Gas
2013—Swap		4,920,000 Mcf	$	0	$	0	$	0	$	3.94	$	1,248
2013—Three Way Collar		1,260,000 Mcf		3.35		4.17		4.88		0		535
2013—Collar		780,000 Mcf		0		4.50		5.02		0		688
2013—Put		1,320,000 Mcf		0		5.00		0		0		1,537
2013—Swaption		600,000 Mcf		0		0		0		4.50		113
2013—Deferred Put Spread		900,000 Mcf		3.75		5.00		0		0		1,003
2014—Sold Call		1,800,000 Mcf		0		0		5.00		0		(168	)
2014—Three Way Collar		7,800,000 Mcf		3.13		4.02		4.68		0		1,424
2014—Swap		4,830,000 Mcf		0		0		0		3.97		359
2014—Collar		1,800,000 Mcf		0		3.51		4.43		0		(22	)
2015—Three Way Collar		2,400,000 Mcf		3.40		4.16		4.63		0		238
2015—Swap		1,200,000 Mcf		0		0		0		4.18		182
		29,610,000 Mcf									$	7,137
Natural Gas Liquids
2013—Swap		162,000 Bbls	$	0	$	0	$	0	$	57.48	$	1,135
2014—Swap		18,000 Bbls		0		0		0		47.46		64
		180,000 Bbls									$	1,199

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We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations. We have used an interest rate swap agreement in the past to manage risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. We currently do not have any interest rate derivative contracts in place.

Item 4. Controls And Procedures.

Evaluation of Disclosure Controls and Procedures

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

Our management (with the participation of our CEO and CFO) has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our CEO and CFO have concluded that, as of June 30, 2013, our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

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

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PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

The information set forth under the subsectionsLegal ReservesandEnvironmental in Note 13,Commitments and Contingencies, to our Consolidated Financial Statements included in Item 1 of Part 1 of this report is incorporated herein by reference.

Item 1A. Risk Factors.

During the quarter ended June 30, 2013, there were no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 6. Exhibits.

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

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SIGNATURES

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

	REX ENERGY CORPORATION (Registrant)
Date: August 8, 2013	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)
Date: August 8, 2013	By:	/s/ Michael L. Hodges
		Michael L. Hodges
		Chief Financial Officer (Principal Financial Officer)

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EXHIBIT INDEX

Exhibit Number	Exhibit Title
3.1	Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.2	Certificate of Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.3	Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on May 11, 2012).
4.1	Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
4.2	Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
4.3	Indenture dated as of December 12, 2012 among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012).
4.4	Form of 8.875% Senior Notes due 2020 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012, and incorporated herein by reference).
4.5	Registration Rights Agreement dated as of December 12, 2012 among Rex Energy Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed with the SEC on December 12, 2012).
4.6	Registration Rights Agreement, dated as of April 26, 2013, among Rex Energy Corporation, the Guarantors named therein, and RBC Capital Markets, LLC, KeyBanc Capital Markets Inc., SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC, on behalf of the initial purchasers named therein (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on April 26, 2013, and incorporated herein by reference).
10.1	2007 Long-Term Incentive Plan, as amended and restated effective May 8, 2013 (included in Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on May 13, 2013 and incorporated herein by reference).
31.1*	Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2*	Certification of Chief Financial Officer (Principal Financial Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

* These exhibits are filed herewith.

** Furnished herewith.

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