Rex Energy 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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

53,628,870 common shares were outstanding on November 4, 2013.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD SEPTEMBER 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 September 30, 2013 (Unaudited) and December 31, 2012		4
		Consolidated Statements of Operations (Unaudited) for the three and nine-month periods ended September  30, 2013 and September 30, 2012		5
		Consolidated Statement of Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) (Unaudited) for the nine-month period ended September 30, 2013		6
		Consolidated Statements of Cash Flows (Unaudited) for the nine-month periods ended September  30, 2013 and September 30, 2012		7
		Notes to Consolidated Financial Statements (Unaudited)		8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		39
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk		53
	Item 4.	Controls and Procedures		54
PART II. OTHER INFORMATION				55
	Item 1.	Legal Proceedings		55
	Item 1A.	Risk Factors		55
	Item 6.	Exhibits		55
SIGNATURES				56
EXHIBIT INDEX				57

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)

	September 30, 2013 (unaudited)			December 31, 2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	23,791		$	43,975
Accounts Receivable		31,953			24,980
Taxes Receivable		6,487			6,429
Short-Term Derivative Instruments		5,741			12,005
Assets Held for Sale		0			2,279
Inventory, Prepaid Expenses and Other		1,713			1,316
Total Current Assets		69,685			90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		685,891			485,448
Unevaluated Oil and Gas Properties		189,144			165,503
Other Property and Equipment		65,597			50,073
Wells and Facilities in Progress		104,341			92,913
Pipelines		7,888			6,116
Total Property and Equipment		1,052,861			800,053
Less: Accumulated Depreciation, Depletion and Amortization		(182,094	)		(146,038	)
Net Property and Equipment		870,767			654,015
Deferred Financing Costs and Other Assets – Net		12,208			10,029
Equity Method Investments		18,902			16,978
Long-Term Derivative Instruments		1,534			704
Total Assets	$	973,096		$	772,710
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	53,212		$	31,134
Accrued Liabilities		65,815			22,421
Short-Term Derivative Instruments		3,983			1,389
Current Deferred Tax Liability		651			539
Liabilities Related to Assets Held for Sale		0			52
Total Current Liabilities		123,661			55,535
8.875% Senior Notes Due 2020		350,000			250,000
Premium (Discount) on Senior Notes – Net		3,162			(1,742	)
Senior Secured Line of Credit and Other Long-Term Debt		2,750			991
Long-Term Derivative Instruments		445			1,510
Long-Term Deferred Tax Liability		34,005			23,625
Other Deposits and Liabilities		5,337			5,675
Future Abandonment Cost		24,230			24,822
Total Liabilities	$	543,590		$	360,416
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 53,619,870 shares issued and outstanding on September 30, 2013 and 53,213,264 shares issued and outstanding on December 31, 2012		52			52
Additional Paid-In Capital		454,933			451,062
Accumulated Deficit		(27,116	)		(39,595	)
Rex Energy Stockholders’ Equity		427,869			411,519
Noncontrolling Interests		1,637			775
Total Stockholders’ Equity		429,506			412,294
Total Liabilities and Stockholders’ Equity	$	973,096		$	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 September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	58,063		$	34,711		$	150,447		$	93,893
Field Services Revenue		4,847			4,170			15,193			8,990
Other Revenue		64			48			164			137
TOTAL OPERATING REVENUE		62,974			38,929			165,804			103,020
OPERATING EXPENSES
Production and Lease Operating Expense		17,203			11,234			43,695			34,505
General and Administrative Expense		8,826			6,858			24,404			18,043
Loss on Disposal of Assets		140			16			1,632			110
Impairment Expense		2,244			292			2,414			3,357
Exploration Expense		3,242			1,206			7,511			3,511
Depreciation, Depletion, Amortization and Accretion		16,267			12,130			40,367			32,297
Field Services Operating Expense		3,652			2,985			10,354			5,706
Other Operating Expense		19			399			910			693
TOTAL OPERATING EXPENSES		51,593			35,120			131,287			98,222
INCOME FROM OPERATIONS		11,381			3,809			34,517			4,798
OTHER INCOME (EXPENSE)
Interest Expense		(6,181	)		(1,118	)		(16,013	)		(4,440	)
Gain (Loss) on Derivatives, Net		(4,624	)		(5,893	)		(1,423	)		5,188
Other Income (Expense)		(30	)		(497	)		2,041			92,241
Loss on Equity Method Investments		(207	)		(174	)		(569	)		(3,738	)
TOTAL OTHER INCOME (EXPENSE)		(11,042	)		(7,682	)		(15,964	)		89,251
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		339			(3,873	)		18,553			94,049
Income Tax (Expense) Benefit		1,493			2,131			(5,622	)		(35,768	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		1,832			(1,742	)		12,931			58,281
Income (Loss) From Discontinued Operations, Net of Income Taxes		0			(258	)		460			(8,662	)
NET INCOME (LOSS)		1,832			(2,000	)		13,391			49,619
Net Income Attributable to Noncontrolling Interests		258			193			912			516
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	1,574		$	(2,193	)	$	12,479		$	49,103
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders	$	0.03		$	(0.04	)	$	0.23		$	1.13
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders		0.00			0.00			0.01			(0.17	)
Basic – Net Income (Loss) Attributable to Rex Common Shareholders	$	0.03		$	(0.04	)	$	0.24		$	0.96
Basic – Weighted Average Shares of Common Stock Outstanding		52,626			52,036			52,560			51,120
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders	$	0.03		$	(0.04	)	$	0.23		$	1.11
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders		0.00			0.00			0.01			(0.17	)
Diluted – Net Income (Loss) Attributable to Rex Common Shareholders	$	0.03		$	(0.04	)	$	0.24		$	0.94
Diluted – Weighted Average Shares of Common Stock Outstanding		53,293			52,805			53,124			52,018

See accompanying notes to the unaudited consolidated financial statements

5

REX ENERGY CORPORATION

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

FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2013

(Unaudited, in Thousands)

	Common Stock				Additional Paid-In Capital			Accumulated Deficit			Rex Energy Stockholders’ Equity			Noncontrolling Interests			Total Stockholders’ Equity
	Shares		Par Value
BALANCE December 31, 2012		53,213	$	52	$	451,062		$	(39,595	)	$	411,519		$	775		$	412,294
Non-Cash Compensation		0		0		3,793			0			3,793			0			3,793
Stock Option Exercises		49		0		534			0			534			0			534
Issuance of Restricted Stock, Net of Forfeitures		358		0		0			0			0			0			0
Capital Distributions		0		0		0			0			0			(646	)		(646	)
Change in Ownership of Noncontrolling Interests		0		0		(456	)		0			(456	)		596			140
Net Income		0		0		0			12,479			12,479			912			13,391
BALANCE September 30, 2013		53,620		52		454,933			(27,116	)		427,869			1,637			429,506

See accompanying notes to the unaudited consolidated financial statements

6

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	13,391		$	49,619
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		569			3,738
Non-Cash Expenses		4,432			2,939
Depreciation, Depletion, Amortization and Accretion		40,367			32,297
(Gain) Loss on Derivatives		1,423			(5,188	)
Cash Settlements of Derivatives		5,540			13,355
Dry Hole Expense		485			613
Deferred Income Tax Expense		10,970			19,416
Impairment Expense		2,414			16,308
(Gain) Loss on Sale of Asset		663			(91,980	)
Changes in operating assets and liabilities
Accounts Receivable		(7,028	)		(8,153	)
Inventory, Prepaid Expenses and Other Assets		(391	)		(50	)
Accounts Payable and Accrued Liabilities		34,750			(5,935	)
Other Assets and Liabilities		(1,830	)		(1,146	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		105,755			25,833
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		246			237
Contributions to Equity Method Investments		(2,493	)		(4,087	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		3,931			122,711
Acquisitions of Undeveloped Acreage		(31,458	)		(43,369	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(197,264	)		(126,823	)
NET CASH USED IN INVESTING ACTIVITIES		(227,038	)		(51,331	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(1,022	)		(155,000	)
Proceeds from Long-Term Debt and Line of Credit		1,750			102,730
Repayments of Loans and Other Long-Term Debt		(1,363	)		(664	)
Proceeds from Senior Notes, Including Premiums		105,000			0
Debt Issuance Costs		(3,004	)		(195	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		0			(234	)
Proceeds from the Exercise of Stock Options		534			0
Distributions by the Partners of Consolidated Subsidiaries		(646	)		(129	)
Purchase of Noncontrolling Interests		(150	)		0
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			70,977
NET CASH PROVIDED BY FINANCING ACTIVITIES		101,099			17,485
NET DECREASE IN CASH		(20,184	)		(8,013	)
CASH – BEGINNING		43,975			11,796
CASH – ENDING	$	23,791		$	3,783
SUPPLEMENTAL DISCLOSURES
Interest Paid		15,313			3,783
Cash Paid for Income Taxes, Net of Refunds		(4,976	)		11,370
NON-CASH ACTIVITIES
Increase in Accrued Capital Expenditures		30,455			7,657

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 consolidated subsidiaries. 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 $0.8 million from Depreciation, Depletion, Amortization and Accretion to Interest Expense on our Consolidated Statement of Operations for the three and nine months ended September 30, 2012, respectively, with no effect on previously reported net income (loss), net income (loss) per share, accumulated deficit or stockholders’ equity. For the nine months ended September 30, 2012, we reclassified approximately $5.9 million from changes in Other Assets and Liabilities to changes in Accounts Payable and Accrued Liabilities 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 Current Report on Form 8-K for the year ended December 31, 2012, dated September 3, 2013.

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.

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, equipment rental 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 nine months ended September 30, 2013 and 2012 (in thousands):

	Exploration and Production			Field Services			Intercompany Eliminations			Consolidated Total
Three Months Ended September 30, 2013
Revenues	$	58,127			6,543			(1,696	)		62,974
Inter-Segment Revenues		0			(1,696	)		1,696			0
Total Revenues		58,127			4,847			0			62,974
Income (Loss) From Continuing Operations, Before Income Taxes	$	192			629			(482	)		339
Three Months Ended September 30, 2012
Revenues	$	34,759			4,839			(669	)		38,929
Inter-Segment Revenues		0			(669	)		669			0
Total Revenues		34,759			4,170			0			38,929
Income (Loss) From Continuing Operations, Before Income Taxes	$	(4,631	)		934			(176	)		(3,873	)
Nine Months Ended September 30, 2013
Revenues	$	150,611			19,668			(4,475	)		165,804
Inter-Segment Revenues		0			(4,475	)		4,475			0
Total Revenues		150,611			15,193			0			165,804
Income (Loss) From Continuing Operations, Before Income Taxes	$	16,464			3,344			(1,255	)		18,553
Nine Months Ended September 30, 2012
Revenues	$	94,030			10,681			(1,691	)		103,020
Inter-Segment Revenues		0			(1,691	)		1,691			0
Total Revenues		94,030			8,990			0			103,020
Income (Loss) From Continuing Operations, Before Income Taxes	$	91,825			2,673			(449	)		94,049
As of September 30, 2013
Total Assets	$	958,429			18,247			(3,580	)		973,096
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 $1.2 million and $2.3 million for the three and nine-month periods ended September 30, 2013, respectively, as compared to $0.6 million and $1.5 million for the three and nine months ended September 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	September 30, 2013
Beginning Balance at December 31, 2012	$	24,822
Future Abandonment Obligation Incurred		899
Future Abandonment Obligation Settled		(1,687	)
Future Abandonment Obligation Revision of Estimated Obligation		160
Future Abandonment Obligation Accretion Expense		2,307
Future Abandonment Cost at September 30, 2013	$	26,501
Less Short-Term Portion		(2,271	)
Long-Term Portion	$	24,230

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 September 30, 2013, we had no assets or liabilities related to 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 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 were primarily related to Accounts Payable and Accrued Liabilities.

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 September 30,					Nine Months Ended September 30,
($ in Thousands)	2013		2012			2013			2012
Revenues:
Oil and Gas Sales	$	0	$	29		$	25		$	81
Total Operating Revenue		0		29			25			81
Costs and Expenses:
Production and Lease Operating Expense		0		97			104			305
General and Administrative Expense		0		60			23			583
Exploration Expense		0		329			97			810
Impairment Expense		0		0			0			12,951
Other Operating Expense (Income)		0		0			(3	)		8
(Gain) Loss on Sale of Asset		0		4			(969	)		148
Other Expense		0		0			0			2
Total Expenses (Income)		0		490			(748	)		14,807
Income (Loss) from Discontinued Operations Before Income Taxes		0		(461	)		773			(14,726	)
Income Tax (Expense) Benefit		0		203			(313	)		6,064
Income (Loss) from Discontinued Operations, net of taxes	$	0	$	(258	)	$	460		$	(8,662	)
Production:
Crude Oil (Bbls)		0		407			356			1,062
Total (Mcfe)		0		2,442			2,136			6,372

5. 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.

In July 2013, the FASB issued ASU 2013-11,Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This ASU clarifies the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The ASU is effective for fiscal years, and interim period within those years, beginning after December 15, 2013. We do not expect this update to have a material impact on our Consolidated Financial Statements.

6. 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 7,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 8,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 nine months ended September 30, 2013, approximately 89.7% of our commodity sales came from six purchasers, with the largest single purchaser accounting for 36.9% 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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7. 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 September 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. Our most recent re-determination occurred during September 2013, resulting in no significant changes to the current Senior Credit Facility. 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 8,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 September 30, 2013 was 2.3 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

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quarters ending on such day to interest expense for such period, known as our interest coverage ratio, is not to be less than 3.0 to 1.0. Our interest coverage ratio as of September 30, 2013 was 4.8 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 September 30, 2013 was 3.0 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. Debt issuance costs of $2.3 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. As of September 30, 2013, we had recorded on our Consolidated Balance Sheet approximately $353.2 million of Senior Notes, net of discounts and premiums.

On October 31, 2013, substantially all of the outstanding Senior Notes were exchanged for an equal principal amount of registered 8.875% senior notes due 2020 pursuant to an effective registration statement on FormS-4 filed on September 3, 2013 under the Securities Act (the “Exchange Notes”). The Exchange Notes are identical to the Senior Notes except that the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used in this Quarterly Report on Form10-Q, the term “Senior Notes” refer to both the originally issued Senior Notes and the Exchange Notes.

We may redeem, at specified redemption prices, some or all of the Senior Notes at any time on or after December 1, 2016. We may also redeem up to 35% of the Senior Notes using the proceeds of certain equity offerings completed before December 1, 2015. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Senior Notes from the holders.

The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. 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. For additional information on our guarantor and non-guarantor subsidiaries, see Note 18,Condensed Consolidating Financial Information, to our Consolidated Financial Statements.

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 September 30, 2013 and December 31, 2012:

($ in Thousands)	September 30, 2013 (Unaudited)			December 31, 2012
8.875% Senior Notes Due 2020	$	350,000		$	250,000
Premium (Discount) on Senior Notes, Net		3,162			(1,742	)
Senior Line of Credit(a)		0			0
Capital Leases and Other Obligations(a)		5,545			2,677
Total Debts		358,707			250,935
Less Current Portion of Long-Term Debt(b)		(2,795	)		(1,686	)
Total Long-Term Debt	$	355,912		$	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 September 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 nine months ended September 30, 2013 was approximately 3.3% and 3.8%, respectively.

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

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8. 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 September 30, 2013, our oil, NGL and natural gas derivative commodity instruments consisted of fixed rate swap contracts, collars, swaptions, puts, three-way collars, deferred put spreads, cap swaps and basis swaps. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as other income or expense on our Consolidated Statements of Operations under the heading Gain (Loss) on Derivatives, Net.

Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. 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. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing.

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. Our derivative contracts for oil, natural gas and NGLs are tied to West Texas Intermediate, Henry Hub and Mont Belvieu pricing, respectively. For additional information on the credit risk with regards to our counterparties, see Note 6,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 received cash settlements of $0.7 million and $4.3 million during the three-month periods ended September 30, 2013 and 2012, respectively, and $5.5 million and $13.4 million during the nine-month periods ended September 30, 2013 and 2012, respectively, under these commodity derivative instruments.

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The following table summarizes the location and amounts of gains and losses on derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012 ($ in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Oil	$	(4,519	)	$	(1,492	)	$	(3,989	)	$	1,780
Natural Gas		1,125			(3,970	)		2,605			2,602
Natural Gas Liquids		(1,230	)		(431	)		(39	)		806
Gain (Loss) on Derivatives, Net	$	(4,624	)	$	(5,893	)	$	(1,423	)	$	5,188

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 $2.8 million and a net asset of $9.8 million at September 30, 2013 and December 31, 2012, respectively.

15

As of September 30, 2013, we had over 80.0% of our current oil production on an annualized basis hedged through 2013 and 2014, over 70.0% of our current gas production on an annualized basis hedged through 2013 and 2014, and approximately 60.0% and 30.0% of our current NGL production on an annualized basis hedged through 2013 and 2014, respectively. These percentages exclude the effects of our basis swaps. Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2013 consisted of:

Period	Volume		Put Option		Floor		Ceiling		Swap		Differential			Fair Market Value ($ in Thousands)
Oil
2013—Collar		15,000 Bbls	$	0	$	92.00	$	97.00	$	0	$	0		$	(80	)
2013—Swap		180,000 Bbls		0		0		0		93.39		0			(1,432	)
2013—Three Way Collar		15,000 Bbls		65.00		85.00		100.00		0		0			(53	)
2014—Three Way Collar		420,000 Bbls		71.29		85.73		104.55		0		0			(181	)
2014—Collar		60,000 Bbls		0		90.00		97.65		0		0			(53	)
2014—Deferred Put Spread		168,000 Bbls		75.00		90.00		0		0		0			(417	)
2014—Swap		30,000 Bbls		0		0		0		93.75		0			(153	)
2014—Cap Swap		360,000 Bbls		80.83		0		0		97.72		0			129
		1,248,000 Bbls												$	(2,240	)
Natural Gas
2013—Swap		2,460,000 Mcf	$	0	$	0	$	0	$	3.94	$	0		$	694
2013—Three Way Collar		630,000 Mcf		3.35		4.17		4.88		0		0			246
2013—Collar		390,000 Mcf		0		4.50		5.02		0		0			329
2013—Put		660,000 Mcf		0		5.00		0		0		0			792
2013—Swaption		300,000 Mcf		0		0		0		4.50		0			(2	)
2013—Deferred Put Spread		450,000 Mcf		3.75		5.00		0		0		0			530
2013—Basis Swap		1,800,000 Mcf		0		0		0		0		(0.35	)		(201	)
2014—Sold Call		1,800,000 Mcf		0		0		5.00		0		0			(113	)
2014—Three Way Collar		7,800,000 Mcf		3.13		4.02		4.68		0		0			1,752
2014—Swap		4,830,000 Mcf		0		0		0		3.97		0			555
2014—Collar		1,800,000 Mcf		0		3.51		4.43		0		0			43
2014—Cap Swap		600,000 Mcf		3.25		0		0		4.15		0			48
2014—Swaption		1,200,000 Mcf		0		0		0		4.51		0			172
2014—Basis Swap		4,800,000 Mcf		0		0		0		0		(0.36	)		(461	)
2015—Three Way Collar		2,400,000 Mcf		3.40		4.16		4.63		0		0			379
2015—Swap		1,200,000 Mcf		0		0		0		4.18		0			262
2015—Cap Swap		600,000 Mcf		3.25		0		0		4.15		0			48
2015—Basis Swap		600,000 Mcf		0		0		0		0		(0.35	)		(36	)
		34,320,000 Mcf												$	5,037
Natural Gas Liquids
2013—Swap		147,000 Bbls	$	0	$	0	$	0	$	55.62	$	0		$	(125	)
2014—Swap		297,000 Bbls		0		0		0		48.69		0			175
		444,000 Bbls												$	50

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The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 is summarized below ($ in thousands):

	September 30,			December 31,
	2013			2012
Short-Term Derivative Assets:
Crude Oil—Collars	$	0		$	90
Crude Oil—Three Way Collars		64			0
Crude Oil—Cap Swap		103			0
Natural Gas Liquids—Swaps		408			535
Natural Gas—Swaps		1,739			2,416
Natural Gas—Swaption		129			354
Natural Gas—Three-Way Collars		1,573			1,021
Natural Gas—Deferred Put Spread		530			0
Natural Gas—Collars		367			4,211
Natural Gas—Puts		792			3,378
Natural Gas—Cap Swap		36			0
Total Short-Term Derivative Assets	$	5,741		$	12,005
Long-Term Derivative Assets:
Crude Oil—Three Way Collar	$	21		$	0
Crude Oil—Cap Swap		34			0
Natural Gas Liquids—Swaps		76			0
Natural Gas—Swaps		466			239
Natural Gas—Swaption		43			0
Natural Gas—Cap Swap		60			0
Natural Gas—Collar		12			0
Natural Gas—Three Way Collar		822			465
Total Long-Term Derivative Assets	$	1,534		$	704
Total Derivative Assets	$	7,275		$	12,709
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(119	)	$	(307	)
Crude Oil—Swaps		(1,585	)		(217	)
Crude Oil—Three-Way Collars		(252	)		(45	)
Crude Oil—Deferred Put Spread		(313	)		0
Crude Oil—Cap Swap		(7	)		0
Natural Gas Liquids—Swaps		(434	)		0
Natural Gas—Three-Way Collars		(14	)		(35	)
Natural Gas—Collars		(5	)		0
Natural Gas—Sold Call		(85	)		0
Natural Gas—Swaps		(577	)		(785	)
Natural Gas—Swaptions		(2	)		0
Natural Gas—Basis Swaps		(590	)		0
Total Short-Term Derivative Liabilities	$	(3,983	)	$	(1,389	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	(67	)	$	(509	)
Crude Oil—Deferred Put Spread		(104	)		0
Crude Oil—Cap Swap		(2	)		0
Crude Oil—Collar		(13	)		0
Natural Gas—Swaps		(117	)		(434	)
Natural Gas—Three-Way Collars		(4	)		(35	)
Natural Gas—Sold Call		(28	)		(366	)
Natural Gas—Collars		(2	)		(166	)
Natural Gas—Basis Swaps		(108	)		0
Total Long-Term Derivative Liabilities	$	(445	)	$	(1,510	)
Total Derivative Liabilities	$	(4,428	)	$	(2,899	)

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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.

Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of September 30, 2013 and December 31, 2012, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

Our Level 3 fair value measurements are comprised of our natural gas basis swap contracts. The fair values recorded as of September 30, 2013 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of September 30, 2013 are included in the table below.

Unobservable Input	Range (price per Mcf)			Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Differential Forward Curve		($0.14) – ($0.50	)	$	(0.26	)	$	(698	)

During the three and nine months ended September 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 on a recurring basis ($ in thousands):

			Fair Value Measurements at September 30, 2013 Using:
	Total Carrying Value as of September 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	$	2,847		0		3,545		(698	)

(a) For information regarding the classification of our derivative contracts on our Consolidated Balance Sheets, please refer to the summary on the previous page.

The value of our oil derivatives are comprised of collar, three-way collar, swap, cap 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 September 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 collars, basis swaps, cap swaps, and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of September 30, 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 September 30,

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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.

The table below sets forth a reconciliation of our commodity derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and nine months ended September 30, 2013 and 2012 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
Beginning Balance of Level 3	$	0		$	0	$	0		$	0
Changes in Fair Value		(721	)		0		(721	)		0
Purchases		0			0		0			0
Settlements Received		23			0		23			0
Ending Balance of Level 3		(698	)		0		(698	)		0

Changes in Fair Value on our Level 3 commodity derivative contracts outstanding for the three and nine months ended September 30, 2013 resulted in a loss of approximately $0.7 million. This amount has been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. There were no outstanding Level 3 commodity derivative contracts as of September 30, 2012 or December 31, 2012.

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	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
8.875% Senior Notes due 2020	$	350,000	$	367,500	$	250,000	$	249,063
Capital Leases and Other Obligations		5,545		5,362		2,677		2,524
Total	$	355,545	$	372,862	$	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.

9. INCOME TAXES

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Income Tax (Expense) Benefit	$	1,493		$	2,131		$	(5,622	)	$	(35,768	)
Effective Tax Rate		(1,843.2	%)		51.6	%		31.9	%		38.2	%

For the three and nine months ended September 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 changes in estimates of current and deferred state taxes identified when completing the state tax returns, permanent differences and changes in state tax rates. For the three and nine months ended September 30, 2012, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily due to permanent differences, state taxes and the reversal of certain valuation allowances that were related to deferred tax assets that we now expect to realize.

10. CAPITAL STOCK

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of September 30, 2013 and December 31, 2012, we had 53,619,870 and 53,213,264 shares of common stock outstanding, respectively. There were no shares of preferred stock outstanding as of September 30, 2013 and December 31, 2012.

11. 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.

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.

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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 nine months ended September 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 nine months ended September 30, 2013 was negligible and $0.2 million, respectively, as compared to $0.1 million and $0.2 million for the three and nine months ended September 30, 2012, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. The intrinsic value of stock options exercised for the nine months ended September 30, 2013, was approximately $0.4 million. The total tax benefit for the nine months ended September 30, 2013 was $0.2 million. The intrinsic value of stock options exercised for the nine months ended September 30, 2012, was approximately $0.1 million. The total tax benefit for the nine months ended September 30, 2012 was negligible.

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

	Outstanding				Exercisable
Exercise Price	Number Outstanding At 9/30/13		Weighted-Average Exercise Price		Number Exercisable At 9/30/13		Weighted-Average Exercise Price
$5.04		46,041	$	5.04		46,041	$	5.04
$9.50		85,000	$	9.50		85,000	$	9.50
$9.99		167,333	$	9.99		167,333	$	9.99
$10.42		29,548	$	10.42		29,548	$	10.42
$11.87		3,500	$	11.87		2,333	$	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	$	0
$22.34		30,000	$	22.34		30,000	$	22.34
		449,087	$	10.85		385,365	$	10.48

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at September 30, 2013 were 4.2 years and $5.2 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at September 30, 2013 were 4.4 years and $4.6 million, respectively. As of September 30, 2013, unrecognized compensation expense related to stock options totaled approximately $0.1 million, which will be recognized over a weighted average period of 1.0 year.

Restricted Stock Awards

During the nine-month period ended September 30, 2013, the Compensation Committee approved the issuance of an aggregate of 414,924 shares of restricted common stock to 38 employees, one director and to three third-party contractors. During the nine-month period ended September 30, 2012, the Compensation Committee approved the issuance of an aggregate of 75,621 shares of restricted stock to 18 employees and one third-party contractor. 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.

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Compensation expense associated with restricted stock awards is recognized on a straight-line basis over the vesting period and is periodically adjusted for estimated forfeiture rates and estimated satisfaction of performance-based goals. Compensation expense associated with restricted stock awards totaled $1.2 million and $3.5 million for the three and nine-month periods ended September 30, 2013, respectively, and $1.2 million and $2.0 million for the three and nine-month periods ended September 30, 2012, respectively. As of September 30, 2013, total unrecognized compensation expense related to restricted common stock grants was approximately $5.0 million, which will be recognized over a weighted average period of 1.9 years.

A portion 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 weighted average fair value of the TSR awards as of December 31, 2012 and September 30, 2013 were $7.80 and $12.20 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:

	Nine Months Ended September 30, 2013			Year Ended December 31, 2012
Expected Dividend Yield		0.0	%		0.0	%
Risk-Free Interest Rate		0.4	%		0.3	%
Expected Volatility – Rex Energy		52.3	%		54.4	%
Expected Volatility – Peer Group		31.2-59.3	%		31.2-58.6	%
Market Index		35.8	%		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 nine months ended September 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		414,924		$	14.97
Forfeitures		(57,484	)	$	11.84
Vested		(174,754	)	$	11.57
Restricted stock awards, as of September 30, 2013		1,614,259		$	13.22

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

There have been no significant changes or developments with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012 and updated in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013.

Environmental

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

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

Letters of Credit

At September 30, 2013, we had posted $1.3 million in various letters of credit to secure our drilling and related operations.

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Lease Commitments

As of September 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 nine months ended September 30, 2013 was $0.2 million and $0.5 million, respectively, as compared to $0 and $0.5 million, respectively, for the three and nine months ended September 30, 2012. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):

2013	$	233
2014		859
2015		807
2016		815
2017		823
Thereafter		133
Total	$	3,670

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 $1.7 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 approximately $0.2 million during the three and nine-month periods ended September 30, 2013 and negligible during the comparable periods of 2012.

Operational Commitments

Pursuant to agreements reached during the fourth quarter of 2010 and the third quarter of 2013, 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 $1.2 million in 2013, $4.9 million in 2014, $3.2 million in 2015 and $1.5 million in 2016, which is consistent with our estimated working interest in this project area. In addition to the contracted drilling rig services, 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 $2.1 million in 2013 and $2.1 million in 2014, which is consistent with our estimated working interest in this project area.

Natural Gas Gathering, Processing and Sales Agreements

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

For the three and nine-month periods ended September 30, 2013 we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $7.6 million and $17.6 million, respectively, compared to the three and nine-month periods ended September 30, 2012, of approximately $2.6 million and $5.7 million, respectively. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows ($ in thousands):

	Total
2013	$	945
2014		7,463
2015		16,525
2016		23,654
2017		29,495
Thereafter		326,367
Total	$	404,449

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Drilling Commitments

During the first quarter of 2012, we entered into a drill-to-earn agreement with MFC Drilling, Inc. (“MFC”). Under the terms and conditions of the agreement, we will acquire at a minimum, through a drill-to-earn structure, a 62.5% working interest in approximately 4,510 acres in Belmont, Guernsey and Noble Counties, Ohio. The agreement provides that in order for us to earn the 62.5% working interest, we will bear the cost for our 62.5% working interest and 100% of the 15% working interest of MFC until such time that we have met the $14.1 million drilling carry obligation. As of September 30, 2013, the remaining drilling carry obligation balance was approximately $6.8 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. As of September 30, 2013, we have satisfied the drilling commitment for the current year. 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 (the “Pennsylvania Impact Fee”) on producers of unconventional natural gas. The fee will be imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:

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

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

For wells spud prior to 2012, the first year fee (considered to be 2011) was due, 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 nine months ended September 30, 2013 we recorded expenses of $0.7 million and $4.6 million, respectively, as compared to three and nine months ended September 30, 2012, we recorded expenses of $0.8 million and $2.2 million, respectively, related to the Pennsylvania Impact Fee. We are recording the accrual of the Pennsylvania 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 September 30, 2013 and December 31, 2012 and are included in Other Liabilities on our Consolidated Balance Sheets.

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13. EARNINGS PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-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 nine months ended September 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 of common stock for the three and nine months ended September 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 0.5 million shares of common stock for the three-month period ended September 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. Stock options to purchase 0.5 million shares of common stock for the nine-month period ended September 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 an anti-dilutive effect on the computation. For the three and nine months ended September 30, 2012, 0.3 million shares of performance-based restricted stock awards were outstanding but included in the computations of diluted net income per share calculations due to performance metrics that have not yet been attained. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
Numerator:
Net Income (Loss) From Continuing Operations, Less Noncontrolling Interests	$	1,574	$	(1,935	)	$	12,019	$	57,765
Net Income (Loss) From Discontinued Operations		0		(258	)		460		(8,662	)
Net Income (Loss)	$	1,574	$	(2,193	)	$	12,479	$	49,103
Denominator:
Weighted Average Common Shares Outstanding - Basic		52,626		52,036			52,560		51,120
Effect of Dilutive Securities:
Employee Stock Options		164		0			137		63
Employee Performance-Based Restricted Stock Awards		503		769			427		835
Weighted Average Common Shares Outstanding - Diluted		53,293		52,805			53,124		52,018
Earnings per Common Share:
Basic — Net Income (Loss) From Continuing Operations	$	0.03	$	(0.04	)	$	0.23	$	1.13
— Net Income (Loss) From Discontinued Operations		0.00		0.00			0.01		(0.17	)
— Net Income (Loss)	$	0.03	$	(0.04	)	$	0.24	$	0.96
Diluted — Net Income (Loss) From Continuing Operations	$	0.03	$	(0.04	)	$	0.23	$	1.11
— Net Income (Loss) From Discontinued Operations		0.00		0.00			0.01		(0.17	)
— Net Income (Loss)	$	0.03	$	(0.04	)	$	0.24	$	0.94

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14. 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 company agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions”) for the purpose of acquiring, managing and operating water treatment, disposal and transportation facilities that are designed to treat, dispose or transport brine and fresh waters used and produced in oil and gas well development activities. The members of Water Solutions are Rex Energy Corporation 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 Statements 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 term loan under which $1.5 million was borrowed as of September 30, 2013. There were no cash contributions during the first nine months of 2013 and 2012. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of September 30, 2013 and December 31, 2012, with no restrictions or obligations to use certain assets to settle associated liabilities:

($ in Thousands)	As of September 30, 2013			As of December 31, 2012
Assets
Cash and Cash Equivalents	$	1,453		$	741
Accounts Receivable		4,008			3,360
Inventory, Prepaid Expenses and Other		96			13
Other Property and Equipment		9,148			3,560
Wells and Facilities in Progress		0			221
Accumulated Depreciation, Depletion and Amortization		(1,429	)		(501	)
Deferred Financing Costs and Other Assets—Net		228			199
Total Assets	$	13,504		$	7,593
Liabilities
Accounts Payable	$	4,051		$	1,554
Accrued Liabilities		1,780			1,036
Senior Secured Line of Credit and Long-Term Debt		2,501			965
Total Liabilities	$	8,332		$	3,555

27

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 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

15. 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 $18.9 million and $17.0 million as of September 30, 2013 and December 31, 2012, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During the first nine months of 2013, we contributed approximately $2.5 million in cash to RW Gathering, as compared to the contributions of approximately $2.0 million in cash to RW Gathering to support current pipeline and gathering line construction in the first nine months of 2012. RW Gathering recorded net losses from continuing operations of $0.5 million and $1.4 million for the three and nine months ended September 30, 2013, respectively, as compared to losses of $0.4 million and $1.3 million for the three and nine months ended September 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 Loss on Equity Method Investments.

During the three and nine-month periods ended September 30, 2013, we incurred approximately $0.3 million and $0.6 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC as compared to approximately $0.2 million and $0.7 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 September 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 interest in Keystone Midstream Services, LLC (“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.

28

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 nine months ended September 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 $11.5 million for the nine-month period ended September 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.

16. IMPAIRMENT EXPENSE

For the three and nine months ended September 30, 2013 we incurred approximately $2.2 million and $2.4 million in impairment expenses, respectively, as compared to $0.3 million and $3.4 million in impairment expenses for the three and nine months ended September 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 September 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 September 30, 2013, we continued to carry the costs of undeveloped properties of approximately $189.1 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.

17. EXPLORATION EXPENSE

For the three and nine months ended September 30, 2013 we incurred approximately $3.2 million and $7.5 million in exploration expenses, respectively, as compared to $1.2 million and $3.5 million in exploration expenses for the same periods ended September 30, 2012, respectively. Approximately $7.0 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 $3.2 million of the expense incurred in 2012 was due to geological and geophysical type expenditures and delay rental payments primarily associated with leases in the Appalachian Basin. An additional $0.3 million 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.

18. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of September 30, 2013, we had $350.0 million of Senior Notes outstanding, as shown in Note 7,Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or the guarantor subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of September 30, 2013:

• Rex Energy I, LLC

• Rex Energy Operating Corporation

• Rex Energy IV, LLC

• PennTex Resources Illinois, Inc.

• R.E. Gas Development, LLC

The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions Holdings and its subsidiaries, R.E. Disposal, LLC (formerly known as NorthStar #3, LLC) and Rex Energy Rockies, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of September 30, 3013, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the Senior Notes, (ii) the combined guarantor subsidiaries, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for the periods ending September 30, 2013 and 2012.

29

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF SEPTEMBER 30, 2013

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

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	22,339		$	1,447		$	5		$	0		$	23,791
Accounts Receivable		29,091			4,008			0			(1,146	)		31,953
Taxes Receivable		0			0			6,487			0			6,487
Short-Term Derivative Instruments		5,741			0			0			0			5,741
Inventory, Prepaid Expenses and Other		1,582			96			35			0			1,713
Total Current Assets		58,753			5,551			6,527			(1,146	)		69,685
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		688,218			0			0			(2,327	)		685,891
Unevaluated Oil and Gas Properties		189,144			0			0			0			189,144
Other Property and Equipment		55,542			10,055			0			0			65,597
Wells and Facilities in Progress		99,431			5,272			0			(362	)		104,341
Pipelines		7,888			0			0			0			7,888
Total Property and Equipment		1,040,223			15,327			0			(2,689	)		1,052,861
Less: Accumulated Depreciation, Depletion and Amortization		(180,713	)		(1,636	)		0			255			(182,094	)
Net Property and Equipment		859,510			13,691			0			(2,434	)		870,767
Deferred Financing Costs and Other Assets—Net		2,427			228			9,553			0			12,208
Equity Method Investments		18,902			0			0			0			18,902
Intercompany Receivables		0			0			582,151			(582,151	)		0
Investment in Subsidiaries – Net		4,442			1,797			230,534			(236,773	)		0
Long-Term Derivative Instruments		1,534			0			0			0			1,534
Total Assets	$	945,568		$	21,267		$	828,765		$	(822,504	)	$	973,096
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	50,294		$	4,064		$	0		$	(1,146	)	$	53,212
Accrued Liabilities		53,132			1,953			10,730			0			65,815
Short-Term Derivative Instruments		3,983			0			0			0			3,983
Current Deferred Tax Liability		0			0			651			0			651
Total Current Liabilities		107,409			6,017			11,381			(1,146	)		123,661
8.875% Senior Notes Due 2020		0			0			350,000			0			350,000
Premium (Discount) on Senior Notes – Net		0			0			3,162			0			3,162
Senior Secured Line of Credit and Other Long-Term Debt		249			2,501			0			0			2,750
Long-Term Derivative Instruments		445			0			0			0			445
Long-Term Deferred Tax Liability		0			0			34,005			0			34,005
Other Deposits and Liabilities		5,337			0			0			0			5,337
Future Abandonment Cost		24,217			13			0			0			24,230
Intercompany Payables		508,296			73,855			0			(582,151	)		0
Total Liabilities		645,953			82,386			398,548			(583,297	)		543,590
Stockholders’ Equity
Common Stock		0			0			52			0			52
Additional Paid-In Capital		177,146			3,188			455,113			(180,514	)		454,933
Accumulated Earnings (Deficit)		122,469			(65,034	)		(24,948	)		(59,603	)		(27,116	)
Rex Energy Stockholders’ Equity		299,615			(61,846	)		430,217			(240,117	)		427,869
Noncontrolling Interests		0			727			0			910			1,637
Total Stockholders’ Equity		299,615			(61,119	)		430,217			(239,207	)		429,506
Total Liabilities and Stockholders’ Equity	$	945,568		$	21,267		$	828,765		$	(822,504	)	$	973,096

30

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2013

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	58,063		$	0		$	0		$	0		$	58,063
Field Services Revenue		0			6,543			0			(1,696	)		4,847
Other Revenue		64			0			0			0			64
TOTAL OPERATING REVENUE		58,127			6,543			0			(1,696	)		62,974
OPERATING EXPENSES
Production and Lease Operating Expense		17,201			2			0			0			17,203
General and Administrative Expense		6,863			617			1,361			(15	)		8,826
Loss on Disposal of Asset		94			46			0			0			140
Impairment Expense		2,244			0			0			0			2,244
Exploration Expense		3,241			1			0			0			3,242
Depreciation, Depletion, Amortization and Accretion		15,876			435			0			(44	)		16,267
Field Services Operating Expense		0			4,821			0			(1,169	)		3,652
Other Operating Expense		19			0			0			0			19
TOTAL OPERATING EXPENSES		45,538			5,922			1,361			(1,228	)		51,593
INCOME (LOSS) FROM OPERATIONS		12,589			621			(1,361	)		(468	)		11,381
OTHER INCOME (EXPENSE)
Interest Expense		(16	)		(26	)		(6,139	)		0			(6,181	)
Loss on Derivatives, Net		(4,624	)		0			0			0			(4,624	)
Other Income (Expense)		(15	)		0			0			(15	)		(30	)
Loss From Equity Method Investments		(207	)		0			0			0			(207	)
Income (Loss) From Equity in Consolidated Subsidiaries		(22	)		22			7,653			(7,653	)		0
TOTAL OTHER INCOME (EXPENSE)		(4,884	)		(4	)		1,514			(7,668	)		(11,042	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		7,705			617			153			(8,136	)		339
Income Tax Benefit		11			61			1,421			0			1,493
INCOME (LOSS) FROM CONTINUING OPERATIONS		7,716			678			1,574			(8,136	)		1,832
Income From Discontinued Operations, Net of Income Taxes		0			0			0			0			0
NET INCOME (LOSS)		7,716			678			1,574			(8,136	)		1,832
Net Income Attributable to Noncontrolling Interests		0			258			0			0			258
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	7,716		$	420		$	1,574		$	(8,136	)	$	1,574

31

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	150,447		$	0		$	0		$	0		$	150,447
Field Services Revenue		0			19,668			0			(4,475	)		15,193
Other Revenue		164			0			0			0			164
TOTAL OPERATING REVENUE		150,611			19,668			0			(4,475	)		165,804
OPERATING EXPENSES
Production and Lease Operating Expense		43,688			7			0			0			43,695
General and Administrative Expense		18,896			1,765			3,814			(71	)		24,404
Loss on Disposal of Asset		1,586			46			0			0			1,632
Impairment Expense		2,414			0			0			0			2,414
Exploration Expense		7,510			1			0			0			7,511
Depreciation, Depletion, Amortization and Accretion		39,434			1,038			0			(105	)		40,367
Field Services Operating Expense		0			13,468			0			(3,114	)		10,354
Other Operating Expense		910			0			0			0			910
TOTAL OPERATING EXPENSES		114,438			16,325			3,814			(3,290	)		131,287
INCOME (LOSS) FROM OPERATIONS		36,173			3,343			(3,814	)		(1,185	)		34,517
OTHER INCOME (EXPENSE)
Interest Expense		(47	)		(66	)		(15,900	)		0			(16,013	)
Loss on Derivatives, Net		(1,423	)		0			0			0			(1,423	)
Other Income (Expense)		2,112			0			0			(71	)		2,041
Loss From Equity Method Investments		(569	)		0			0			0			(569	)
Income (Loss) From Equity in Consolidated Subsidiaries		(44	)		44			25,510			(25,510	)		0
TOTAL OTHER INCOME (EXPENSE)		29			(22	)		9,610			(25,581	)		(15,964	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		36,202			3,321			5,796			(26,766	)		18,553
Income Tax (Expense) Benefit		(11,546	)		(759	)		6,683			0			(5,622	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		24,656			2,562			12,479			(26,766	)		12,931
Income From Discontinued Operations, Net of Income Taxes		0			460			0			0			460
NET INCOME (LOSS)		24,656			3,022			12,479			(26,766	)		13,391
Net Income Attributable to Noncontrolling Interests		0			912			0			0			912
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	24,656		$	2,110		$	12,479		$	(26,766	)	$	12,479

32

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2013

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	24,656		$	3,022		$	12,479		$	(26,766	)	$	13,391
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		569			0			0			0			569
Non-Cash Expenses		(180	)		65			4,547			0			4,432
Depreciation, Depletion, Amortization and Accretion		39,434			1,038			0			(105	)		40,367
Deferred Income Tax Expense (Benefit)		12,060			1,169			(2,259	)		0			10,970
Loss on Derivatives		1,423			0			0			0			1,423
Cash Settlements of Derivatives		5,540			0			0			0			5,540
Dry Hole Expense		485			0			0			0			485
(Gain) Loss on Sale of Asset		1,586			(923	)		0			0			663
Impairment Expense		2,414			0			0			0			2,414
Changes in operating assets and liabilities
Accounts Receivable		(2,628	)		(669	)		0			(3,731	)		(7,028	)
Inventory, Prepaid Expenses and Other Assets		(316	)		(66	)		(9	)		0			(391	)
Accounts Payable and Accrued Liabilities		23,174			(1,687	)		9,241			4,022			34,750
Other Assets and Liabilities		(1,495	)		(88	)		(247	)		0			(1,830	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		106,722			1,861			23,752			(26,580	)		105,755
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		139,294			688			(165,201	)		25,219			0
Proceeds from Joint Venture Acreage Management		246			0			0			0			246
Contributions to Equity Method Investments		(2,493	)		0			0			0			(2,493	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		697			3,234			0			0			3,931
Acquisitions of Undeveloped Acreage		(31,456	)		(2	)		0			0			(31,458	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(193,964	)		(4,661	)		0			1,361			(197,264	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(87,676	)		(741	)		(165,201	)		26,580			(227,038	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			1,750			0			0			1,750
Repayments of Long-Term Debt and Lines of Credit		0			(1,022	)		0			0			(1,022	)
Repayments of Loans and Other Long-Term Debt		(934	)		(429	)		0			0			(1,363	)
Proceeds from Senior Notes, including Premium		0			0			105,000			0			105,000
Debt Issuance Costs		0			0			(3,004	)		0			(3,004	)
Proceeds from the Exercise of Stock Options		0			0			534			0			534
Purchase of Non-Controlling Interests		0			(150	)		0			0			(150	)
Distributions by the Partners of Consolidated Subsidiaries		0			(646	)		0			0			(646	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(934	)		(497	)		102,530			0			101,099
NET INCREASE (DECREASE) IN CASH		18,112			623			(38,919	)		0			(20,184	)
CASH – BEGINNING		4,227			824			38,924			0			43,975
CASH - ENDING	$	22,339		$	1,447		$	5		$	0		$	23,791

33

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF DECEMBER 31, 2012

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

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	4,227		$	824		$	38,924		$	0		$	43,975
Accounts Receivable		26,490			3,367			0			(4,877	)		24,980
Taxes Receivable		0			0			6,429			0			6,429
Short-Term Derivative Instruments		12,005			0			0			0			12,005
Assets Held For Sale		0			2,279			0			0			2,279
Inventory, Prepaid Expenses and Other		1,277			13			26			0			1,316
Total Current Assets		43,999			6,483			45,379			(4,877	)		90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		486,706			0			0			(1,258	)		485,448
Unevaluated Oil and Gas Properties		165,503			0			0			0			165,503
Other Property and Equipment		45,613			4,455			0			5			50,073
Wells and Facilities in Progress		88,204			4,780			0			(71	)		92,913
Pipelines		6,116			0			0			0			6,116
Total Property and Equipment		792,142			9,235			0			(1,324	)		800,053
Less: Accumulated Depreciation, Depletion and Amortization		(145,514	)		(674	)		0			150			(146,038	)
Net Property and Equipment		646,628			8,561			0			(1,174	)		654,015
Deferred Financing Costs and Other Assets—Net		2,427			199			7,403			0			10,029
Equity Method Investments		16,978			0			0			0			16,978
Intercompany Receivables		3,795			0			440,269			(444,064	)		0
Investment in Subsidiaries—Net		(227	)		(232	)		193,790			(193,331	)		0
Long-Term Derivative Instruments		704			0			0			0			704
Total Assets	$	714,304		$	15,011		$	686,841		$	(643,446	)	$	772,710
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	29,818		$	1,560		$	0		$	(244	)	$	31,134
Accrued Liabilities		19,891			1,036			1,494			0			22,421
Short-Term Derivative Instruments		1,389			0			0			0			1,389
Current Deferred Tax Liability		0			0			539			0			539
Liabilities Related to Assets Held For Sale		0			52			0			0			52
Total Current Liabilities		51,098			2,648			2,033			(244	)		55,535
8.875% Senior Notes Due 2020		0			0			250,000			0			250,000
Discount on Senior Notes		0			0			(1,742	)		0			(1,742	)
Senior Secured Line of Credit and Other Long-Term Debt		26			5,598			0			(4,633	)		991
Long-Term Derivative Instruments		1,510			0			0			0			1,510
Long-Term Deferred Tax Liability		0			0			23,625			0			23,625
Other Deposits and Liabilities		5,675			0			0			0			5,675
Future Abandonment Cost		24,822			0			0			0			24,822
Intercompany Payables		367,704			76,360			0			(444,064	)		0
Total Liabilities		450,835			84,606			273,916			(448,941	)		360,416
Stockholders’ Equity
Common Stock		0			0			52			0			52
Additional Paid-In Capital		177,143			(407	)		451,062			(176,736	)		451,062
Accumulated Deficit		86,326			(69,144	)		(38,189	)		(18,588	)		(39,595	)
Rex Energy Stockholders’ Equity		263,469			(69,551	)		412,925			(195,324	)		411,519
Noncontrolling Interests		0			(44	)		0			819			775
Total Stockholders’ Equity		263,469			(69,595	)		412,925			(194,505	)		412,294
Total Liabilities and Stockholders’ Equity	$	714,304		$	15,011		$	686,841		$	(643,446	)	$	772,710

34

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2012

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	34,711		$	0		$	0		$	0		$	34,711
Field Services Revenue		0			4,839			0			(669	)		4,170
Other Revenue		76			0			0			(28	)		48
TOTAL OPERATING REVENUE		34,787			4,839			0			(697	)		38,929
OPERATING EXPENSES
Production and Lease Operating Expense		11,228			6			0			0			11,234
General and Administrative Expense		5,372			246			1,275			(35	)		6,858
Loss on Disposal of Asset		6			10			0			0			16
Impairment Expense		280			12			0			0			292
Exploration Expense		1,206			0			0			0			1,206
Depreciation, Depletion, Amortization and Accretion		11,992			163			0			(25	)		12,130
Field Services Operating Expense		0			3,482			0			(497	)		2,985
Other Operating Income		399			0			0			0			399
TOTAL OPERATING EXPENSES		30,483			3,919			1,275			(557	)		35,120
INCOME (LOSS) FROM OPERATIONS		4,304			920			(1,275	)		(140	)		3,809
OTHER INCOME (EXPENSE)
Interest Expense		(17	)		(8	)		(1,093	)		0			(1,118	)
Loss on Derivatives, Net		(5,893	)		0			0			0			(5,893	)
Other Expense		(462	)		0			0			(35	)		(497	)
Loss From Equity Method Investments		(174	)		0			0			0			(174	)
Income (Loss) From Equity in Consolidated Subsidiaries		(11	)		11			(1,188	)		1,188			0
TOTAL OTHER INCOME (EXPENSE)		(6,557	)		3			(2,281	)		1,153			(7,682	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(2,253	)		923			(3,556	)		1,013			(3,873	)
Income Tax (Expense) Benefit		1,156			(388	)		1,363			0			2,131
INCOME (LOSS) FROM CONTINUING OPERATIONS		(1,097	)		535			(2,193	)		1,013			(1,742	)
Loss From Discontinued Operations, Net of Income Taxes		0			(258	)		0			0			(258	)
NET INCOME (LOSS)		(1,097	)		277			(2,193	)		1,013			(2,000	)
Net Income Attributable to Noncontrolling Interests		0			193			0			0			193
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(1,097	)	$	84		$	(2,193	)	$	1,013		$	(2,193	)

35

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	93,893		$	0		$	0		$	0		$	93,893
Field Services Revenue		0			10,681			0			(1,691	)		8,990
Other Revenue		190			0			0			(53	)		137
TOTAL OPERATING REVENUE		94,083			10,681			0			(1,744	)		103,020
OPERATING EXPENSES
Production and Lease Operating Expense		34,491			14			0			0			34,505
General and Administrative Expense		15,266			692			2,155			(70	)		18,043
Loss on Disposal of Asset		101			9			0			0			110
Impairment Expense		3,277			80			0			0			3,357
Exploration Expense		3,511			0			0			0			3,511
Depreciation, Depletion, Amortization and Accretion		32,038			317			0			(58	)		32,297
Field Services Operating Expense		0			6,943			0			(1,237	)		5,706
Other Operating Expense		693			0			0			0			693
TOTAL OPERATING EXPENSES		89,377			8,055			2,155			(1,365	)		98,222
INCOME (LOSS) FROM OPERATIONS		4,706			2,626			(2,155	)		(379	)		4,798
OTHER INCOME (EXPENSE)
Interest Expense		(46	)		(12	)		(4,382	)		0			(4,440	)
Gain on Derivatives, Net		5,188			0			0			0			5,188
Other Income (Expense)		92,311			0			0			(70	)		92,241
Loss From Equity Method Investments		(3,738	)		0			0			0			(3,738	)
Income (Loss) From Equity in Consolidated Subsidiaries		(36	)		36			52,901			(52,901	)		0
TOTAL OTHER INCOME (EXPENSE)		93,679			24			48,519			(52,971	)		89,251
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		98,385			2,650			46,364			(53,350	)		94,049
Income Tax (Expense) Benefit		(37,705	)		(802	)		2,739			0			(35,768	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		60,680			1,848			49,103			(53,350	)		58,281
Loss From Discontinued Operations, Net of Income Taxes		0			(8,662	)		0			0			(8,662	)
NET INCOME (LOSS)		60,680			(6,814	)		49,103			(53,350	)		49,619
Net Income Attributable to Noncontrolling Interests		0			516			0			0			516
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	60,680		$	(7,330	)	$	49,103		$	(53,350	)	$	49,103

36

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2012

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	60,680		$	(6,814	)	$	49,103		$	(53,350	)	$	49,619
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		3,738			0			0			0			3,738
Non-Cash Expense		32			7			2,900			0			2,939
Depreciation, Depletion, Amortization and Accretion		32,038			317			0			(58	)		32,297
Deferred Income Tax Expense (Benefit)		39,127			(17,949	)		(1,762	)		0			19,416
Gain on Derivatives		(5,188	)		0			0			0			(5,188	)
Cash Settlements of Derivatives		13,355			0			0			0			13,355
Dry Hole Expense		336			277			0			0			613
(Gain) Loss on Sale of Asset		(92,137	)		157			0			0			(91,980	)
Impairment Expense		3,278			13,030			0			0			16,308
Changes in operating assets and liabilities
Accounts Receivable		(3,715	)		(2,988	)		(1,464	)		14			(8,153	)
Inventory, Prepaid Expenses and Other Assets		(59	)		7			2			0			(50	)
Accounts Payable and Accrued Liabilities		(6,652	)		44			261			412			(5,935	)
Other Assets and Liabilities		(919	)		(227	)		0			0			(1,146	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		43,914			(14,139	)		49,040			(52,982	)		25,833
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		791			13,313			(66,579	)		52,475			0
Proceeds from Joint Venture Acreage Management		237			0			0			0			237
Contributions to Equity Method Investments		(4,087	)		0			0			0			(4,087	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		121,339			1,372			0			0			122,711
Acquisitions of Undeveloped Acreage		(43,350	)		(19	)		0			0			(43,369	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(126,429	)		(901	)		0			507			(126,823	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(51,499	)		13,765			(66,579	)		52,982			(51,331	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			730			102,000			0			102,730
Repayments of Long-Term Debt and Lines of Credit		0			0			(155,000	)		0			(155,000	)
Repayments of Loans and Other Long-Term Debt		(572	)		(92	)		0			0			(664	)
Debt Issuance Costs		0			0			(195	)		0			(195	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		0			0			(234	)		0			(234	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			0			70,977			0			70,977
Distributions by the Partners of Consolidated Subsidiaries		0			(129	)		0			0			(129	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(572	)		509			17,548			0			17,485
NET INCREASE (DECREASE) IN CASH		(8,157	)		135			9			0			(8,013	)
CASH – BEGINNING		11,337			409			50			0			11,796
CASH - ENDING	$	3,180		$	544		$	59		$	0		$	3,783

37

19. SUBSEQUENT EVENTS

On October 28, 2013, Water Solutions, as guarantor, and its wholly-owned subsidiary, Keystone Clearwater Solutions, LLC (collectively “Keystone Clearwater”), as borrower, entered into agreements with M&T Bank (“M&T”) to obtain a revolving line of credit (“Demand Note”) and an equipment line of credit (“Equipment Note”).

Demand Note

The borrowing base for the Demand Note is the lesser of (a) $4.0 million or (b) 80% of Keystone Clearwater’s Accounts Receivable which are less than 90 days old. Borrowings under the Demand Note are to be used for working capital and general corporate purposes. At Keystone Clearwater’s election, borrowings under the Demand Note bear interest per annum equal to an adjusted LIBOR rate or an adjusted base rate, as defined below. The adjusted LIBOR rate is equal 2.75 percentage points above the greater of (a) one-month LIBOR, adjusting daily, or (b) one-day LIBOR. The adjusted base rate is equal to 2.0 percentage points above the rate of interest announced by M&T as its prime rate. All interest that is accrued through the last day of any calendar month will be due and payable by the tenth day of the next calendar month. While there is no stated maturity date for amounts outstanding under the Demand Note, in certain circumstances, Keystone Clearwater may be required to repay amounts outstanding on demand from M&T. As of November 8, 2013, there was approximately $2.7 million outstanding under the Demand Note.

The Demand Note agreement does not contain any collateral requirements on behalf of Keystone Clearwater, nor does it contain any financial covenant requirements.

Equipment Note

Maximum borrowings under the Equipment Note are equal to $6.0 million and are to be used for purposes of making equipment or vehicle acquisitions up to a maximum of 80% of the costs of such assets. Borrowings under the Equipment Note bear interest per annum equal to the three month LIBOR plus 3.0 percentage points. All interest is due and payable on the first day of each fiscal quarter. Maturity dates will vary with each borrowing, but will generally be three to four years from the date of borrowing. In certain circumstances, Keystone Clearwater may be required to prepay any loans that are outstanding.

The Equipment Note contains covenants that restrict Keystone Clearwater’s ability to, among other things, materially change their business; incur indebtedness; make loans to others; incur liens; make investments; or become a guarantor. Borrowings under the Equipment Note are collateralized with liens covering 80% of the value of assets purchased with associated loans under the Equipment Note. The Equipment Note also requires that Keystone Clearwater meet certain financial covenants regarding tangible net worth, fixed charge coverage ratio and a debt to EBITDA ratio (as defined in the Equipment Note). EBITDA is a non-GAAP financial measure used by the management of Keystone Clearwater and by other users of Keystone Clearwater’s financial statements, such as 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, amortization and other similar non-cash activity. The Equipment Note requires that tangible net worth (i) not be less than $2.5 million measured annually, and (ii) not be less than $2.5 million plus 30% of annual net income commencing with the fiscal year ended December 31, 2013 and each fiscal year thereafter. Also, Keystone Clearwater’s fixed charge coverage ratio for four consecutive fiscal quarters ending at the end of each fiscal quarter shall not be less than 1.75 to 1.0. Keystone Clearwater’s debt to EBITDA ratio for the trailing 12 month period ending on the last day of the measurement period shall not be greater than 2.25 to 1.0.

38

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 Current Report on Form 8-K filed on September 3, 2013, 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.

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 nine months ended September 30, 2013, we produced 7,899.9 MMcfe and 20,216.6 MMcfe, respectively, in the Appalachian Basin. In the Illinois Basin, we produced 197.4 MBls and 580.0 MBbls during the three and nine months ended September 30, 2013, respectively. Overall, our production for the three and nine months ended September 30, 2013 averaged 98,745 Mcfe per day and 86,799 Mcfe per day, respectively. As of September 30, 2013, we had 23.0 gross (14.1 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 September 30, 2013:

	Wells Drilled				Wells Completed				Wells Placed In Service
	2013		2012		2013		2012		2013		2012
Appalachian Basin		11.0		7.2		19.0		11.9		14.0		9.5
Illinois Basin		5.0		5.0		7.0		7.0		8.0		8.0
Total		16.0		12.2		26.0		18.9		22.0		17.5

For the nine months ended September 30, 2013:

	Wells Drilled				Wells Completed				Wells Placed In Service
	2013		2012		2013		2012		2013		2012
Appalachian Basin		31.0		19.6		37.0		25.7		30.0		21.2
Illinois Basin		17.0		17.0		24.0		24.0		24.0		24.0
Total		48.0		36.6		61.0		49.7		54.0		45.2

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

39

million (after the initial purchasers’ premiums, commissions and offering expenses but excluding accrued interests 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 7, “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 7, “Long-Term Debt” for additional information on our Senior Credit Facility and the Senior Notes.

Our credit facility is re-determined twice a year, and most recently in September 2013. No significant changes were made to the credit agreement or borrowing base during the re-determination.

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 nine months ended September 30, 2013 and 2012.

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Production:
Oil and Condensate (Bbls)		252,426		182,759		664,257		524,149
Natural Gas (Mcf)		6,169,918		4,865,953		16,413,517		13,191,301
Natural Gas Liquids (Bbls)		233,350		96,610		549,559		236,570
Total (Mcfe)(a)		9,084,574		6,542,167		23,696,413		17,755,615
Average daily production:
Oil and Condensate (Bbls)		2,744		1,987		2,433		1,913
Natural Gas (Mcf)		67,064		52,891		60,123		48,143
Natural Gas Liquids (Bbls)		2,536		1,050		2,013		863
Total (Mcfe)(a)		98,745		71,111		86,799		64,802
Average sales price(b):
Oil and Condensate (per Bbl)	$	102.38	$	89.00	$	95.79	$	92.70
Natural Gas (per Mcf)	$	3.47	$	2.98	$	3.76	$	2.72
Natural Gas Liquids (per Bbl)	$	46.25	$	40.95	$	45.63	$	39.69
Total (per Mcfe)(a)	$	6.39	$	5.31	$	6.35	$	5.29
Average NYMEX prices(c):
Oil (per Bbl)	$	105.94	$	92.32	$	98.17	$	96.23
Natural Gas (per Mcf)	$	3.56	$	2.89	$	3.68	$	2.59

40

(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 nine months ended September 30, 2013 and 2012.

	Production and Revenue by Basin
	For Three Months Ended September 30,				For Nine Months Ended September 30,
	2013		2012		2013		2012
Appalachian
Revenue – Natural Gas(a)	$	21,426,517	$	14,491,897	$	61,741,634	$	35,917,200
Volumes (Mcf)		6,169,918		4,865,953		16,413,517		13,191,301
Average Price	$	3.47	$	2.98	$	3.76	$	2.72
Revenue – Condensate(a)	$	5,239,202	$	341,243	$	7,768,178	$	442,835
Volumes (Bbl)		54,978		4,083		84,292		5,386
Average Price	$	95.30	$	83.58	$	92.16	$	82.22
Revenue – Natural Gas Liquids(a)	$	10,793,295	$	3,955,708	$	25,076,069	$	9,389,150
Volumes (Bbl)		233,350		96,610		549,559		236,570
Average Price	$	46.25	$	40.95	$	45.63	$	39.69
Average Production Cost per Mcfe(b)(c)	$	1.32	$	0.91	$	1.23	$	1.04
Illinois
Revenue – Oil(a)	$	20,604,040	$	15,922,285	$	55,861,052	$	48,143,366
Volumes (Bbl)		197,448		178,676		579,965		518,764
Average Price	$	104.35	$	89.11	$	96.32	$	92.80
Average Production Cost per Bbl(b)	$	32.86	$	27.52	$	31.47	$	31.00

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

(b) Excludes ad valorem and severance taxes.

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

General Overview

Operating revenue for the three and nine months ended September 30, 2013 increased 61.8% and 60.9%, 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 7,900 MMcfe for the three-month period ended September 30, 2013, from 5,470 MMcfe for the three-month period ended September 30, 2012, or approximately 44.4%, while realized natural gas prices have increased to $3.47 per Mcf from $2.98 per Mcf and NGL prices have increased to $46.25 per barrel from $40.95 per barrel over the same period in 2012. In the Illinois Basin, our production grew to 197.4 MBbls for the three-month period ended September 30, 2013 from 178.7 MBbls for the three-month period ended September 30, 2012, or approximately 10.5%. For the nine months ended September 30, 2013, production in the Appalachian Basin has increased 38.1% to 20,217 MMcfe from the same period in 2012, while production in the Illinois Basin for the nine months ended September 30, 2013 increased 11.8% to 580.0 MBls from the same period in 2012. Average commodity sales prices for the first nine months of 2013 increased 20.0% when compared to average commodity sales prices over the same period in 2012.

Operating expenses increased $16.5 million and $33.1 million for the three and nine-month periods ended September 30, 2013, respectively, as compared to the same periods in 2012. Operating expenses primarily comprise: Production and Lease Operating Expense, G&A Expense, Gain/Loss on Disposal of Assets, Exploration Expense, Impairment Expense, DD&A Expense and Field Operating Expenses. The increases in operating expenses were largely attributable to Production and Lease Operating Expense, G&A Expense, DD&A Expense and Field Service Operating Expense. 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 September 30, 2013 to the Three Months Ended September 30, 2012.

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

	For Three Months Ended September 30,
	2013			2012		Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	25,843		$	16,263	$	9,580			58.9	%
Oil derivatives realized(a)	$	(2,404	)	$	—	$	(2,404	)		(100.0	%)
Total oil and condensate revenue and derivatives realized	$	23,439		$	16,263	$	7,176			44.1	%
Gas sales revenue	$	21,427		$	14,492	$	6,935			47.9	%
Gas derivatives realized(a)	$	3,227		$	4,119	$	(892	)		(21.7	%)
Total gas revenue and derivatives realized	$	24,654		$	18,611	$	6,043			32.5	%
Natural gas liquid revenue	$	10,793		$	3,956	$	6,837			172.8	%
Natural gas liquid derivatives realized(a)	$	(82	)	$	155	$	(237	)		(152.9	%)
Total natural gas liquid revenue	$	10,711		$	4,111	$	6,600			160.5	%
Consolidated sales	$	58,063		$	34,711	$	23,352			67.3	%
Consolidated derivatives realized(a)	$	741		$	4,274	$	(3,533	)		(82.7	%)
Total oil, NGL and gas revenue and derivatives realized	$	58,804		$	38,985	$	19,819			50.8	%
Total Mcfe Production		9,084,574			6,542,167		2,542,407			38.9	%
Average Realized Price per Mcfe	$	6.47		$	5.96	$	0.51			8.6	%

(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 third quarter of 2013, after the effect of derivative activities, was $6.47 per Mcfe, an increase of 8.6%, or $0.51 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 4.5%, or $0.16 per Mcf, to $3.99 per Mcf. The average price for oil and condensate, after the effect of derivative activities, increased 4.3%, or $3.88 per barrel, to $92.86 per barrel. The average price for NGLs, after the effect of derivative activities, increased 7.9%, or $3.35 per barrel, to $45.90 per barrel. Our derivative activities effectively increased net realized price by $0.08 per Mcfe in the third quarter of 2013 and $0.65 per Mcfe in the third quarter of 2012.

Historically, we have received premium natural gas pricing as compared to Henry Hub pricing. During the third quarter of 2013, our natural gas was sold at a discount to Henry Hub pricing. In an effort to mitigate this impact, we have entered into natural gas basis swap derivative contracts to provide basis protection between Henry Hub and Dominion Appalachia pricing differentials. As of September 30, 2013, we had basis swap derivatives on approximately 29.2%, 19.4% and 7.3% of our current quarter annualized production for 2013, 2014 and 2015, respectively. We anticipate continuing to add to this position to protect ourselves from further unfavorable pricing differentials.

Production volumes in the third quarter of 2013 increased 38.9% from the third quarter of 2012. Natural gas production increased approximately 26.8%, oil production increased approximately 38.1% and NGL production increased approximately 141.5%. 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 September 30, 2013 averaged 98.7 Mcfe per day, of which 67.9% was attributable to natural gas, 16.7% to oil and 15.4% to NGL production.

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

	For Three Months Ended September 30,
	2013			2012			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	58,063		$	34,711			23,352			67.3	%
Field Services Revenue		4,847			4,170			677			16.2	%
Other Revenue		64			48			16			33.3	%
TOTAL OPERATING REVENUE		62,974			38,929			24,045			61.8	%
OPERATING EXPENSES
Production and Lease Operating Expense		17,203			11,234			5,969			53.1	%
General and Administrative Expense		8,826			6,858			1,968			28.7	%
Loss on Disposal of Asset		140			16			124			775.0	%
Impairment Expense		2,244			292			1,952			668.5	%
Exploration Expense		3,242			1,206			2,036			168.8	%
Depreciation, Depletion, Amortization and Accretion		16,267			12,130			4,137			34.1	%
Field Service Operating Expense		3,652			2,985			667			22.3	%
Other Operating Expense		19			399			(380	)		(95.2	%)
TOTAL OPERATING EXPENSES		51,593			35,120			16,473			46.9	%
INCOME FROM OPERATIONS		11,381			3,809			7,572			198.8	%
OTHER INCOME (EXPENSE)
Interest Expense		(6,181	)		(1,118	)		(5,063	)		452.9	%
Loss on Derivatives, Net		(4,624	)		(5,893	)		1,269			(21.5	%)
Other Income (Expense)		(30	)		(497	)		467			(94.0	%)
Loss on Equity Method Investments		(207	)		(174	)		(33	)		19.0	%
TOTAL OTHER EXPENSE		(11,042	)		(7,682	)		(3,360	)		43.7	%
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		339			(3,873	)		4,212			(108.8	%)
Income Tax Benefit		1,493			2,131			(638	)		(29.9	%)
INCOME (LOSS) FROM CONTINUING OPERATIONS		1,832			(1,742	)		3,574			205.2	%
Loss From Discontinued Operations, Net of Income Taxes		0			(258	)		258			(100.0	%)
NET INCOME (LOSS)		1,832			(2,000	)		3,832			191.6	%
Net Income Attributable to Noncontrolling Interests		258			193			65			33.7	%
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	1,574		$	(2,193	)		3,767			(171.8	%)

Field Services Revenue for the three months ended September 30, 2013 increased approximately $0.7 million from the third 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 $6.0 million, or 53.1%, in the third 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 third quarter of 2013, transportation, capacity and processing fees accounted for approximately 44.3% of our total Production and Lease Operating Expense as compared to 30.6% in the third 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 third quarter of 2013 increased approximately $2.0 million, or 28.7%, to $8.8 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 increased approximately $2.0 million in the third quarter of 2013 from the same period in 2012. 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 third quarter of 2013 is primarily related to non-operated acreage in Clearfield County, Pennsylvania that is not contiguous with the operator’s existing development area. These leases are approaching expiration, and the operator has no current plans to extend the leases or develop this acreage. As of September 30, 2013, we continued to carry the costs of undeveloped properties of approximately $189.1 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 September 30, 2013 was approximately $3.2 million as compared to $1.2 million for the three months ended September 30, 2012. Approximately $2.4 million of expense incurred in third quarter 2013 was due to geological and geophysical type expenditures and delay rental payments associated with leases in the Appalachian Basin and $0.8 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 third 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 September 30, 2013 increased approximately $4.1 million, or 34.1%, from $12.1 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 third quarter of 2013 totaled approximately $3.7 million as compared to $3.0 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 September 30, 2013 was approximately $6.2 million as compared to $1.1 million during the third 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, which carries a higher interest rate compared to amounts outstanding under our Senior Credit Facility as of September 30, 2012. We expect our interest expense to remain higher than in the prior year period as a result of the net increase in debt from our issuance of the Senior Notes.

Loss on Derivatives, Net was approximately $4.6 million for the third quarter of 2013 as compared to $5.9 million for the same period in 2012. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and natural 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 natural gas production volumes given the highly volatile oil, NGL and natural gas commodities market.

Net Income Tax Benefit was approximately $1.5 million for the three months ended September 30, 2013 as compared to a benefit of $2.1 million for the three months ended September 30, 2012. In addition to the variance in Income (Loss) from Continuing Operations, Before Income Tax, the change was primarily due to changes in estimates of current and deferred state taxes identified when completing the state tax returns.

Net Income (Loss) Attributable to Rex Energy for the third quarter of 2013 was income of approximately $1.6 million, as compared to a loss of $2.2 million for the comparable period in 2012 as a result of the factors discussed above.

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Comparison of the Nine Months Ended September 30, 2013 to the Nine Months Ended September 30, 2012.

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

	For Nine Months Ended September 30,
	2013			2012			Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	63,629		$	48,587		$	15,042			31.0	%
Oil derivatives realized(a)	$	(2,737	)	$	(286	)	$	(2,451	)		N/M
Total oil and condensate revenue and derivatives realized	$	60,892		$	48,301		$	12,591			26.1	%
Gas sales revenue	$	61,742		$	35,917		$	25,825			71.9	%
Gas derivatives realized(a)	$	7,831		$	13,394		$	(5,563	)		(41.5	%)
Total gas revenue and derivatives realized	$	69,573		$	49,311		$	20,262			41.1	%
Natural gas liquid revenue	$	25,076		$	9,389		$	15,687			167.1	%
Natural gas liquid derivatives realized(a)	$	446		$	248		$	198			79.8	%
Total natural gas liquid revenue	$	25,522		$	9,637		$	15,885			164.8	%
Consolidated sales	$	150,447		$	93,893		$	56,554			60.2	%
Consolidated derivatives realized(a)	$	5,540		$	13,356		$	(7,816	)		(58.5	%)
Total oil, NGL and gas revenue and derivatives realized	$	155,987		$	107,249		$	48,738			45.4	%
Total Mcfe Production		23,696,413			17,755,615			5,940,798			33.5	%
Average Realized Price per Mcfe	$	6.58		$	6.04		$	0.54			8.9	%

(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 nine months of 2013, after the effect of derivative activities, was $6.58 per Mcfe, an increase of 8.9%, or $0.54 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 13.4%, or $0.50 per Mcf, to $4.24 per Mcf. The average price for oil and condensate, after the effect of derivative activities, decreased 0.5%, or $0.48 per barrel, to $91.67 per barrel. The average price for NGLs, after the effect of derivative activities, increased 14.0%, or $5.70 per barrel, to $46.44 per barrel. Our derivative activities effectively increased net realized price by $0.23 per Mcfe in the first nine months of 2013 and $0.75 per Mcfe in the first nine months of 2012.

Production volumes in the first nine months of 2013 increased 33.5% from the same period in 2012. Natural gas production increased approximately 24.4%, oil production increased approximately 26.7% and NGL production increased approximately 132.3%. 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 nine months ended September 30, 2013 averaged 86,799 Mcfe per day, of which 69.3% was attributable to natural gas, 16.8% to oil and 13.9% to NGL production.

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

	For Nine Months Ended September 30,
	2013			2012			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	150,447		$	93,893			56,554			60.2	%
Field Services Revenue		15,193			8,990			6,203			69.0	%
Other Revenue		164			137			27			19.7	%
TOTAL OPERATING REVENUE		165,804			103,020			62,784			60.9	%
OPERATING EXPENSES
Production and Lease Operating Expense		43,695			34,505			9,190			26.6	%
General and Administrative Expense		24,404			18,043			6,361			35.3	%
Loss on Disposal of Asset		1,632			110			1,522			1,383.6	%
Impairment Expense		2,414			3,357			(943	)		(28.1	%)
Exploration Expense		7,511			3,511			4,000			113.9	%
Depreciation, Depletion, Amortization and Accretion		40,367			32,297			8,070			25.0	%
Field Service Operating Expense		10,354			5,706			4,648			81.5	%
Other Operating Expense		910			693			217			31.3	%
TOTAL OPERATING EXPENSES		131,287			98,222			33,065			33.7	%
INCOME FROM OPERATIONS		34,517			4,798			29,719			619.4	%
OTHER INCOME (EXPENSE)
Interest Expense		(16,013	)		(4,440	)		(11,573	)		260.7	%
Gain (Loss) on Derivatives, Net		(1,423	)		5,188			(6,611	)		(127.4	%)
Other Income		2,041			92,241			(90,200	)		(97.8	%)
Loss on Equity Method Investments		(569	)		(3,738	)		3,169			(84.8	%)
TOTAL OTHER INCOME (EXPENSE)		(15,964	)		89,251			(105,215	)		(117.9	%)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		18,553			94,049			(75,496	)		(80.3	%)
Income Tax Expense		(5,622	)		(35,768	)		30,146			(84.3	%)
INCOME FROM CONTINUING OPERATIONS		12,931			58,281			(45,350	)		(77.8	%)
Income (Loss) From Discontinued Operations, Net of Income Taxes		460			(8,662	)		9,122			(105.3	%)
NET INCOME		13,391			49,619			(36,228	)		(73.0	%)
Net Income Attributable to Noncontrolling Interests		912			516			396			76.7	%
NET INCOME ATTRIBUTABLE TO REX ENERGY	$	12,479		$	49,103			(36,624	)		(74.6	%)

Field Services Revenue for the nine months ended September 30, 2013 and 2012 was approximately $15.2 million and $9.0 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 Expense increased approximately $9.2 million, or 26.6%, for the nine months ended September 30, 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 nine months ended September 30, 2013, the transportation and marketing agreements accounted for approximately 40.3% of our Production and Lease Operating Expense as compared to 28.2% 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 Expense for the nine months ended September 30, 2013 increased approximately $6.4 million, or 35.3%, to $24.4 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 nine months ended September 30, 2013 and 2012 totaled approximately $2.4 million and $3.4 million, respectively. We continually monitor the carrying value of our oil and natural gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during both periods is primarily related to non-operated acreage in Clearfield County, Pennsylvania that is not contiguous with the operator’s existing development area. These leases are approaching expiration, and the operator has no current plans to extend the leases or develop this acreage. As of September 30, 2013, we continued to carry the costs of undeveloped properties of approximately $189.1 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 nine months ended September 30, 2013 was approximately $7.5 million, as compared to $3.5 million for the same period during 2012. Approximately $5.1 million of expense incurred in the first nine months of 2013 was due to geological

46

and geophysical type expenditures and delay rental payments associated with leases in the Appalachian Basin and $2.4 million due to geological and geophysical type expenditures and dry hole expense in the Illinois Basin. Approximately $3.2 million of the expense incurred in 2012 was due to geological and geophysical expenditures and delay rental payments primarily associated with leases in the Appalachian Basin. The remaining $0.3 million spent during the first nine months of 2012 is related to the plugging of two exploratory Marcellus Shale wells that were spud during 2011 in Butler County, Pennsylvania. Minimal drilling was completed on these wells before a strategic decision was made to abandon the well locations and reallocate the remaining capital to other leases that will enable us to hold additional acreage by production.

DD&A Expense for the nine months ended September 30, 2013 increased to approximately $40.4 million, an increase of 25.0%, from $32.3 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 nine months ended September 30, 2013 and 2012 was approximately $10.4 million and $5.7 million, respectively. Our field services operating expense is 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 nine months ended September 30, 2013 was approximately $16.0 million, as compared to $4.4 million during the same period in 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 September 30, 2012. We expect our interest expense to remain higher than the prior year period as a result of the net increase in debt from our issuance of the Senior Notes.

Gain (Loss) on Derivatives, Net was a loss of approximately $1.4 million for the nine months ended September 30, 2013 as compared to a gain of $5.2 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 nine months ended September 30, 2013 and 2012 totaled approximately $2.0 million and $92.2 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, before a post-closing adjustment of $0.5 million and recognized a gain of approximately $92.2 million. For the nine months ended September 30, 2013, we received payment of approximately $2.3 million representing amounts that were being held in escrow related to the sale.

Income Tax Expense was approximately $5.6 million for the nine months ended September 30, 2013 as compared to $35.8 million for the nine months ended September 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. Also contributing to the period-over-period change are changes in estimates of current and deferred state taxes identified when completing the state tax returns.

Net Income Attributable to Rex Energy for the nine months ended September 30, 2013 was approximately $12.5 million as compared to $49.1 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 September 30,				For Nine Months Ended September 30,
	2013		2012		2013		2012
EBITDAX (in thousands)(a)	$	34,882	$	22,815	$	94,228	$	62,363
LOE per Mcfe(b)	$	1.89	$	1.72	$	1.84	$	1.79
G&A per Mcfe	$	0.97	$	1.05	$	1.03	$	1.02

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

(b) For nine months ended September 30, 2012, excludes retroactive accrual of Pennsylvania Impact Fee, which equates to approximately $0.15 per Mcfe on a company-wide basis.

EBITDAX (Non-GAAP)

EBITDAX (Non-GAAP) from continuing operations increased approximately $12.1 million to $34.9 million for the three-month period ended September 30, 2013 as compared to the same period in 2012. EBITDAX from continuing operations increased approximately $31.9 million to $94.2 million for the nine-month period ended September 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 and transporting it to a sales market and includes processing and marketing fees. LOE per Mcfe increased to $1.89 for the three months ended September 30, 2013 as compared to $1.72 for the same period in 2012. LOE per Mcfe increased to $1.84 for the nine months ended September 30, 2013 as compared to $1.79 for the same period in 2012. For comparative purposes, we have excluded approximately $0.15 per Mcfe from the calculation of our first nine months of 2012 lifting cost which represents the retroactive portion of the Pennsylvania impact fee for wells spud prior to 2012. Since the first quarter 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 nine months ended September 30, 2013, transportation, capacity and processing fees accounted for approximately 44.3% and 40.3%, respectively, of our lifting cost as compared to 30.6% and 28.2% 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. Various agreements that we have entered include firm capacity rights, for which we may incur a fee for unused capacity. 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 G&A 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 G&A expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe decreased to approximately $0.97 for the three-month period ended September 30, 2013 as compared to $1.05 for the same period in 2012. G&A expenses per Mcfe increased to approximately $1.03 for the nine-month period ended September 30, 2013 as compared to $1.02 for the same period in 2012. The decrease for the three-month period ended September 30, 2013 is predominately due to the growth of our production base.

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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 nine months ended September 30, 2013, we spent $228.7 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 $290.0 to $310.0 million. We funded our capital program with net cash flows from operations and the remaining net proceeds from our issuance of $350.0 million aggregate principal amount of Senior Notes after repayment of outstanding amounts under our Senior Credit Facility. 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 in the short and intermediate terms 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 our 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 natural 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 September 30, 2013, we had a $325.0 million borrowing base under our Senior Credit Facility with maximum lender commitments of $215.0 million. We did not have any amounts outstanding under our Senior Credit Facility as of September 30, 2013. 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 7,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 $78.1 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 Nine Months Ended September 30, 2013 and 2012

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

	Nine Months Ended September 30, ($ in Thousands)
	2013			2012
Cash flows provided by operating activities	$	105,755		$	25,833
Cash flows used in investing activities		(227,038	)		(51,331	)
Cash flows provided by financing activities		101,099			17,485
Net decrease in cash and cash equivalents	$	(20,184	)	$	(8,013	)

Net cash provided by operating activities increased by approximately $79.9 million in the first nine 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 investing activities increased from $51.3 million during the first nine months of 2012 to approximately $227.0 million in the first nine months of 2013. This change can be primarily attributed to the net proceeds of our interest in Keystone Midstream 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 nine months of 2013.

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Net cash provided by financing activities increased to approximately $101.1million for the first nine months of 2013 from cash provided by financing activities of approximately $17.5 million for the first nine 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, compared to net repayments of debt during 2012 of approximately $52.3 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 September 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 5, “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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net Income From Continuing Operations	$	1,832		$	(1,742	)	$	12,931		$	58,281
Net Income Attributable to Noncontrolling Interests		(258	)		(193	)		(912	)		(516	)
Income From Continuing Operations Attributable to Rex Energy		1,574			(1,935	)		12,019			57,765
Add Back Non-Recurring Losses(a)		—			—			—			2,809
Add Back Depletion, Depreciation, Amortization and Accretion		16,267			12,130			40,367			32,297
Add Back Non-Cash Compensation Expense		1,365			1,305			3,788			2,147
Add Back Interest Expense		6,181			1,118			16,013			4,440
Add Back Impairment Expense		2,244			292			2,414			3,357
Add Back Exploration Expenses		3,242			1,206			7,511			3,511
Add Back (Less) Loss (Gain) on Disposal of Assets(b)		140			526			(620	)		(92,128	)
Add Back (Less) Loss (Gain) from Financial Derivatives		4,624			5,893			1,423			(5,188	)
Add Back Cash Settlement of Financial Derivatives		741			4,273			5,540			13,355
Less Non-Cash Portion of Noncontrolling Interests		(198	)		(36	)		(404	)		(64	)
Add Back (Less) Income Tax Expense (Benefit)		(1,493	)		(2,131	)		5,622			35,768
Add Back Non-Cash Portion of Equity Method Investments		195			174			555			4,294
EBITDAX From Continuing Operations	$	34,882		$	22,815		$	94,228		$	62,363
Net Income (Loss) From Discontinued Operations	$	—		$	(258	)	$	460		$	(8,662	)
Less Back Non-Cash Compensation Income		—			(43	)		—			(31	)
Add Back Impairment Expense		—			—			—			12,951
Add Back Exploration Expenses		—			329			97			810
Add Back (Less) Loss (Gain) on Disposal of Assets		—			4			(969	)		148
Add Back (Less) Income Tax Expense (Benefit)		—			(203	)		313			(6,064	)
Add EBITDAX From Discontinued Operations	$	—		$	(171	)	$	(99	)	$	(848	)
EBITDAX (Non-GAAP)	$	34,882		$	22,644		$	94,129		$	61,515

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

^(b)  Includes gain on sale of Keystone Midstream of approximately $92.7 million for the nine months ended September 30, 2012, and $2.3 million for the nine months ended September 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 nine months ended September 30, 2013, the net realized gains on oil, NGL and natural gas derivatives were approximately $0.7 million and $5.5 million, respectively, as compared to net realized gains of approximately $4.3 million and $13.4 million for the comparable periods in 2012, respectively. These gains are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of September 30, 2013, we had over 80.0% of our current oil production on an annualized basis hedged through 2013 and 2014, respectively, over 70.0% of our current natural gas production on an annualized basis hedged through 2013 and 2014, respectively, and approximately 60.0% and 30.0% of our current NGL production on an annualized basis hedged through 2013 and 2014, respectively.

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

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

Contractual Obligations

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. Our contractual obligations include long-term debt, operating leases, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2012, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our issuance of additional Senior Notes in April 2013. As a result of the issuance of the additional Senior Notes, our annual interest expense related to the Senior Notes is $31.6 million due semi-annually on June 1 and December 1, with the first interest payment made on June 1, 2013. See Item 1. Financial Statements—Note 7, “Long-Term Debt” for additional information on the Senior Notes.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

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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 September 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 nine months of the 2013 average would reduce our gross revenues, before the effects of derivatives, for the remaining three months of 2013 by approximately $5.0 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, cap swaps, basis swaps, put options, swaptions and three way collars. Our derivative contracts for oil, natural gas and NGLs are tied to West Texas Intermediate, Henry Hub and Mont Belvieu pricing, respectively. 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 September 30, 2013, we had the following commodity derivative contracts outstanding:

Period	Volume		Put Option		Floor		Ceiling		Swap		Differential			Fair Market Value ($ in Thousands)
Oil
2013—Collar		15,000 Bbls	$	0	$	92.00	$	97.00	$	0	$	0		$	(80	)
2013—Swap		180,000 Bbls		0		0		0		93.39		0			(1,432	)
2013—Three Way Collar		15,000 Bbls		65.00		85.00		100.00		0		0			(53	)
2014—Three Way Collar		420,000 Bbls		71.29		85.73		104.55		0		0			(181	)
2014—Collar		60,000 Bbls		0		90.00		97.65		0		0			(53	)
2014—Deferred Put Spread		168,000 Bbls		75.00		90.00		0		0		0			(417	)
2014—Swap		30,000 Bbls		0		0		0		93.75		0			(153	)
2014—Cap Swap		180,000 Bbls		80.83		0		0		97.72		0			129
		1,248,000 Bbls												$	(2,240	)
Natural Gas
2013—Swap		2,460,000 Mcf	$	0	$	0	$	0	$	3.94	$	0		$	694
2013—Three Way Collar		630,000 Mcf		3.35		4.17		4.88		0		0			246
2013—Collar		390,000 Mcf		0		4.50		5.02		0		0			329
2013—Put		660,000 Mcf		0		5.00		0		0		0			792
2013—Swaption		300,000 Mcf		0		0		0		4.50		0			(2	)
2013—Deferred Put Spread		450,000 Mcf		3.75		5.00		0		0		0			530
2013—Basis Swap		1,800,000 Mcf		0		0		0		0		(0.35	)		(201	)
2014—Sold Call		1,800,000 Mcf		0		0		5.00		0		0			(113	)
2014—Three Way Collar		7,800,000 Mcf		3.13		4.02		4.68		0		0			1,752
2014—Swap		4,830,000 Mcf		0		0		0		3.97		0			555
2014—Collar		1,800,000 Mcf		0		3.51		4.43		0		0			43
2014—Cap Swap		600,000 Mcf		3.25		0		0		4.15		0			48
2014—Swaption		1,200,000 Mcf		0		0		0		4.51		0			172
2014—Basis Swap		4,800,000 Mcf		0		0		0		0		(0.36	)		(461	)
2015—Three Way Collar		2,400,000 Mcf		3.40		4.16		4.63		0		0			379
2015—Swap		1,200,000 Mcf		0		0		0		4.18		0			262
2015—Cap Swap		600,000 Mcf		3.25		0		0		4.15		0			48
2015—Basis Swap		600,000 Mcf		0		0		0		0		(0.35	)		(36	)
		34,320,000 Mcf												$	5,037
Natural Gas Liquids
2013—Swap		147,000 Bbls	$	0	$	0	$	0	$	55.62	$	0		$	(125	)
2014—Swap		297,000 Bbls		0		0		0		48.69		0			175
		444,000 Bbls												$	50

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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 September 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 September 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 12,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 September 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: November 8, 2013	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)
Date: November 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).
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.

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