Rex Energy 10-Q 2015 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, 2015

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	x	Accelerated filer	¨
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

55,737,213 common shares were outstanding on November 6, 2015.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD SEPTEMBER 30, 2015

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, 2015 (Unaudited) and December 31, 2014	4
		Consolidated Statements of Operations (Unaudited) for the three and nine-month periods ended September 30, 2015 and September 30, 2014	5
		Consolidated Statement of Changes in Noncontrolling Interests and Stockholders’ Equity (Unaudited) for the nine-month period ended September 30, 2015	6
		Consolidated Statements of Cash Flows (Unaudited) for the nine-month periods ended September 30, 2015 and September 30, 2014	7
		Notes to Consolidated Financial Statements (Unaudited)	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	35
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	49
	Item 4.	Controls and Procedures	50
PART II. OTHER INFORMATION			52
	Item 1.	Legal Proceedings	52
	Item 1A.	Risk Factors	52
	Item 6.	Exhibits	52
SIGNATURES			53
EXHIBIT INDEX			54

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;

● 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;

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

● the willingness and ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls;

● 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 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;

● 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 this Quarterly Report on Form 10-Q and Under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014, 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. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

3

Item 1. Financial Statements.  

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

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

	September 30, 2015 (unaudited)			December 31, 2014
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,150		$	17,978
Accounts Receivable		29,138			43,936
Taxes Receivable		19			504
Short-Term Derivative Instruments		29,194			29,265
Inventory, Prepaid Expenses and Other		2,169			3,403
Assets Held for Sale		—			34,257
Total Current Assets		63,670			129,343
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,202,256			1,079,039
Unevaluated Oil and Gas Properties		288,800			322,413
Other Property and Equipment		45,930			46,361
Wells and Facilities in Progress		125,153			127,655
Pipelines		14,275			15,657
Total Property and Equipment		1,676,414			1,591,125
Less: Accumulated Depreciation, Depletion and Amortization		(631,977	)		(366,917	)
Net Property and Equipment		1,044,437			1,224,208
Deferred Financing Costs and Other Assets – Net		16,271			17,070
Equity Method Investments		—			17,895
Long-Term Derivative Instruments		11,749			4,904
Long-Term Deferred Tax Asset		10,648			8,301
Total Assets	$	1,146,775		$	1,401,721
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	29,551		$	53,340
Current Maturities of Long-Term Debt		668			1,176
Accrued Liabilities		51,964			59,478
Short-Term Derivative Instruments		763			421
Current Deferred Tax Liability		10,648			8,301
Liabilities Related to Assets Held for Sale		—			25,115
Total Current Liabilities		93,594			147,831
Long-Term Derivative Instruments		3,425			2,377
Senior Secured Line of Credit and Long-Term Debt		69,132			251
8.875% Senior Notes Due 2020		350,000			350,000
6.25% Senior Notes Due 2022		325,000			325,000
Premium on Senior Notes, Net		2,442			2,725
Other Deposits and Liabilities		3,372			4,018
Future Abandonment Cost		40,745			38,146
Total Liabilities	$	887,710		$	870,348
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 16,100 issued and    outstanding on September 30, 2015 and on December 31, 2014	$	1		$	1
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 54,975,151 shares    issued and outstanding on September 30, 2015 and 54,174,763 shares issued and outstanding on    December 31, 2014		54			54
Additional Paid-In Capital		622,245			617,826
Accumulated Deficit		(363,235	)		(90,749	)
Rex Energy Stockholders’ Equity		259,065			527,132
Noncontrolling Interests		—			4,241
Total Stockholders’ Equity		259,065			531,373
Total Liabilities and Stockholders’ Equity	$	1,146,775		$	1,401,721

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,
	2015			2014			2015			2014
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	37,565		$	73,448		$	137,437		$	227,650
Other Revenue		8			18			30			92
TOTAL OPERATING REVENUE		37,573			73,466			137,467			227,742
OPERATING EXPENSES
Production and Lease Operating Expense		30,616			27,674			90,310			69,338
General and Administrative Expense		5,376			9,288			23,507			27,179
(Gain) Loss on Disposal of Asset		(230	)		174			(465	)		468
Impairment Expense		139,810			—			264,677			41
Exploration Expense		807			1,462			2,242			4,890
Depreciation, Depletion, Amortization and Accretion		27,124			26,375			82,788			66,454
Other Operating Expense (Income)		183			(24	)		5,304			3
TOTAL OPERATING EXPENSES		203,686			64,949			468,363			168,373
INCOME (LOSS) FROM OPERATIONS		(166,113	)		8,517			(330,896	)		59,369
OTHER EXPENSE
Interest Expense		(11,886	)		(10,946	)		(36,097	)		(25,236	)
Gain on Derivatives, Net		28,649			12,316			45,487			2,315
Other Income		20			3			119			20
Loss on Equity Method Investments		—			(202	)		(411	)		(610	)
TOTAL OTHER INCOME (EXPENSE)		16,783			1,171			9,098			(23,511	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(149,330	)		9,688			(321,798	)		35,858
Income Tax (Expense) Benefit		20,037			(4,069	)		20,653			(13,839	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(129,293	)		5,619			(301,145	)		22,019
Income From Discontinued Operations, Net of Income Taxes		34,617			970			38,149			3,963
NET INCOME (LOSS)		(94,676	)		6,589			(262,996	)		25,982
Net Income (Loss) Attributable to Noncontrolling Interests		(1	)		895			2,245			3,340
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(94,675	)	$	5,694		$	(265,241	)	$	22,642
Preferred Stock Dividends		2,415			—			7,245			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(97,090	)	$	5,694		$	(272,486	)	$	22,642
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(2.44	)	$	0.11		$	(5.74	)	$	0.41
Basic – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.64			0.00			0.67			0.01
Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(1.80	)	$	0.11		$	(5.07	)	$	0.42
Basic – Weighted Average Shares of Common Stock Outstanding		53,936			53,214			53,748			53,493
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(2.44	)	$	0.10		$	(5.74	)	$	0.40
Diluted – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.64			0.00			0.67			0.01
Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(1.80	)	$	0.10		$	(5.07	)	$	0.41
Diluted – Weighted Average Shares of Common Stock Outstanding		53,936			57,991			53,748			55,254

See accompanying notes to the unaudited consolidated financial statements

5

REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN NONCONTROLLING INTERESTS AND STOCKHOLDERS’ EQUITY

FOR THE NINE-MONTHS ENDED SEPTEMBER 30, 2015

(Unaudited, in Thousands)

	Common Stock				Preferred Stock
	Shares		Par Value		Shares		Par Value		Additional Paid-In Capital			Accumulated Deficit			Rex Energy Stockholders' Equity			Noncontrolling Interests			Total Stockholders’ Equity
BALANCE December 31, 2014		54,175	$	54		16	$	1	$	617,826		$	(90,749	)	$	527,132		$	4,241		$	531,373
Non-Cash Compensation		—		—		—		—		4,851			—			4,851			—			4,851
Issuance of Restricted Stock, Net of    Forfeitures		800		—		—		—		—			—			—			—			—
Dividends Declared on Preferred Stock    ($150.00 per preferred share)		—		—		—		—		—			(7,245	)		(7,245	)		—			(7,245	)
Capital Distributions		—		—		—		—		—			—			—			(830	)		(830	)
Sale of Consolidated Subsidiary		—		—		—		—		(432	)		—			(432	)		(5,656	)		(6,088	)
Net Income (Loss)		—		—		—		—		—			(265,241	)		(265,241	)		2,245			(262,996	)
BALANCE September 30, 2015		54,975	$	54		16	$	1	$	622,245		$	(363,235	)	$	259,065		$	-		$	259,065

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,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(262,996	)	$	25,982
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		411			610
Non-cash Expenses		5,691			5,146
Depreciation, Depletion, Amortization and Accretion		82,866			69,014
Gain on Derivatives		(45,487	)		(2,315	)
Cash Settlements of Derivatives		40,102			(3,331	)
Dry Hole Expense		468			237
Deferred Income Tax Expense		—			14,592
Impairment Expense		264,677			41
(Gain) Loss on Sale of Assets		(509	)		385
Gain on Sale of Water Solutions		(57,014	)		—
Changes in operating assets and liabilities
Accounts Receivable		12,015			(9,854	)
Inventory, Prepaid Expenses and Other Assets		1,092			(1,038	)
Accounts Payable and Accrued Liabilities		(26,103	)		36,060
Other Assets and Liabilities		(1,794	)		(1,966	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		13,419			133,563
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		54			210
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		76,251			412
Proceeds from Joint Venture		16,611			—
Acquisitions of Undeveloped Acreage		(26,511	)		(153,628	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(163,207	)		(310,353	)
NET CASH USED IN INVESTING ACTIVITIES		(96,802	)		(463,359	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(108,335	)		(248,146	)
Proceeds from Long-Term Debt and Line of Credit		186,813			193,041
Repayments of Loans and Other Notes Payable		(1,337	)		(1,998	)
Proceeds from Senior Notes, Net of Discounts and Premiums		—			325,000
Debt Issuance Costs		(629	)		(6,731	)
Proceeds from the Issuance of Preferred Stock, Net		—			155,011
Dividends Paid on Preferred Stock		(7,245	)		—
Proceeds from the Exercise of Stock Options		—			421
Distributions by the Partners of Consolidated Joint Ventures		(830	)		(1,080	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		68,437			415,518
NET INCREASE (DECREASE) IN CASH		(14,946	)		85,722
CASH – BEGINNING		18,096			1,900
CASH – ENDING	$	3,150		$	87,622
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	$	3,150		$	87,285
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE	$	—		$	337
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest		33,686			12,774
Cash Paid for Income Taxes		(502	)		(4,643	)
NON-CASH ACTIVITIES
Increase (Decrease) in Accrued Liabilities for Capital Expenditures		(8,651	)		7,042

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 Basin and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling and 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.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

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

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014.

Discontinued Operations

Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 3, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

During December 2014, our board of directors approved and committed to a plan to sell Water Solutions Holdings, LLC and its related subsidiaries (“Water Solutions”), of which we owned a 60% interest. The sale of Water Solutions closed in July 2015. As a result, the assets and liabilities of Water Solutions were classified as held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2014, and the results of operations have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for the three and nine-month periods ended September 30, 2015 and 2014.

2. 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.

8

Accretion expense totaled $1.1 million and $3.1million for the three and nine months ended September 30, 2015, respectively, and $1.3 million and $2.9 million for the three and nine months ended September 30, 2014, 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, 2015
Beginning Balance at January 1, 2015	$	40,099
Future Abandonment Obligation Incurred		752
Future Abandonment Obligation Settled		(1,563	)
Future Abandonment Obligation Cancelled or Sold		(119	)
Future Abandonment Obligation Revision of Estimated Obligation		195
Future Abandonment Obligation Accretion Expense		3,100
Total Future Abandonment Cost1	$	42,464

¹ Includes approximately $1.7 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

In December 2014, our board of directors approved a formal plan to sell Water Solutions, of which we own a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.1 million in net proceeds, resulting in a gain of approximately $57.0 million. The transaction is recorded as Discontinued Operations. Any post-closing adjustments are expected to be settled during the fourth quarter of 2015. Water Solutions operates and manages water sourcing, water transfer, equipment rental, trucking and water disposal services, primarily in the Appalachian Basin.

The carrying value of the assets and liabilities of Water Solutions that were classified as held for sale in the accompanying Consolidated Balance Sheets at December 31, 2014 are as follows:

	December 31,
($ in Thousands)	2014
Assets:
Cash and Cash Equivalents	$	118
Accounts Receivable		13,226
Inventory, Prepaid Expenses and Other		163
Total Current Assets		13,507
Other Property and Equipment, Net		19,690
Wells and Facilities in Progress		688
Intangible Assets, Net		372
Total Long-Term Assets		20,750
Total Assets Held for Sale	$	34,257
Liabilities:
Accounts Payable	$	3,694
Current Maturities of Long-Term Debt		6,236
Accrued Liabilities		6,304
Total Current Liabilities		16,234
Senior Secured Line of Credit and Long-Term Debt		8,881
Total Long-Term Liabilities		8,881
Total Liabilities Related to Assets Held for Sale	$	25,115
Net Assets Held for Sale	$	9,142

9

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

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in Thousands)	2015			2014			2015			2014
Revenues:
Field Services Revenue	$	1,479		$	13,071		$	33,086		$	41,462
Total Operating Revenue		1,479			13,071			33,086			41,462
Costs and Expenses:
General and Administrative Expense		82			1,086			1,961			2,825
Depreciation, Depletion, Amortization and Accretion		2			989			78			2,560
Field Services Operating Expense		1,228			9,567			25,981			30,912
Gain on Sale of Asset		(2	)		(91	)		(44	)		(84	)
Interest Expense		56			134			487			482
Other (Income) Expense		(56,956	)		16			(56,836	)		50
Total Costs and Expenses		(55,590	)		11,701			(28,373	)		36,745
Income from Discontinued Operations Before Income Taxes		57,069			1,370			61,459			4,717
Income Tax Expense		(22,452	)		(400	)		(23,310	)		(754	)
Income from Discontinued Operations, net of taxes	$	34,617		$	970		$	38,149		$	3,963

4. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS

Water Solutions

As described in Note 3 above, we sold Water Solutions pursuant to a purchase and sale agreement with American Water.  

ArcLight Capital Partners, LLC

On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight will participate and fund 35.0% of the estimated well costs for the designated wells. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. The remainder of the proceeds will be received as additional wells are drilled and completed. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us, leaving ArcLight with a 17.5% working interest. ArcLight also has the option to participate in the development of 17 additional wells in 2016; if ArcLight exercises this option, ArcLight will participate and fund 20% of the estimated well costs for the designated wells in return for a 20% working interest. If ArcLight elects to participate in the 2016 wells, the wells will also be subject to certain return on investment and internal rate of return thresholds, which, once meant, will revert 50% of ArcLight’s working interest in the wells back to us. As of September 30, 2015, ArcLight had paid approximately $24.9 million for their interest in wells that have been drilled or are in the process of being drilled.

The ArcLight transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized.

5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. This ASU will be effective for periods beginning after December 15, 2015, for public companies, and

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early adoption is permitted, including adoption in an interim period. We are currently evaluating the potential effect of this ASU but do not believe that it will have a material impact on our Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements. As of September 30, 2015, we had approximately $13.8 million in net deferred financing costs that would be potentially reclassified to reduce the debt carrying balance.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:

1) Identify the contract(s) with a customer.

2) Identify the performance obligations in the contract.

3) Determine the transaction price.

4) Allocate the transaction price to the performance obligations in the contract.

5) Recognize revenue when (or as) the entity satisfies a performance obligation.

An entity should apply the amendments in this ASU using one of the following two methods:

1) Retrospectively to each prior reporting period presented.

2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.

In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption.

In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs with Line-of-Credit Arrangements. This ASU clarifies the presentation of debt issuance costs associated with line-of-credit arrangements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires the presentation of debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related 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.

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We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the nine months ended September 30, 2015, approximately 91.7% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 44.1% of commodity sales. We believe the continued 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.

7. LONG-TERM DEBT

Senior Credit Facility

We maintain a revolving credit facility evidenced by a credit agreement, dated March 27, 2013 and most recently amended on September 4, 2015 (the “Senior Credit Facility”). As of September 30, 2015, the borrowing base under the Senior Credit Facility was $350.0 million; however, the Senior Credit Facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a subfacility exists for up to $60.0 million of letters of credit. As of September 30, 2015, loans made under the Senior Credit Facility were set to mature on September 12, 2019. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of September 30, 2015, we had $69.0 million in outstanding borrowings and approximately $270.3 million available to borrow. There were no borrowings as of December 31, 2014.    

The Senior Credit Facility requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio and net senior secured debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of September 30, 2015 was approximately 3.4 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of net senior secured debt to EBITDAX for the trailing twelve months must not exceed 3.0 to 1.0. Our ratio of net senior secured debt to EBITDAX as of September 30, 2015 was approximately 0.7 to 1.0.

2020 Senior Notes and 2022 Senior Notes

As of September 30, 2015 and December 31, 2014, we had recorded on our Consolidated Balance Sheets approximately $350.0 million of 8.875% senior notes due 2020 (the “2020 Senior Notes”) and approximately $325.0 million of 6.25% senior notes due 2022 (the “2022 Senior Notes”) (collectively, the “Senior Notes”). The Senior Notes are unsecured, and are governed by indentures with substantially similar terms and provisions (the “Indentures”).  The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25:1.  As of September 30, 2015, our Fixed Charge Coverage Ratio was 1.73.  We expect our Fixed Charge Coverage Ratio to be less than 2.25:1 for the rest of 2015 and 2016. As a result, we anticipate that our ability to incur debt, pay dividends or make certain other restricted payments will be subject to the more restrictive provisions of the Indentures for those periods. The Indentures also contain customary events of default. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.  Management does not believe that any acceleration of payment will occur within the next twelve months.

As of September 30, 2015 and December 31, 2014, we had recorded on our Consolidated Balance Sheets approximately $2.4 million and $2.7 million, respectively, of a net premium related to the Senior Notes. The amortization of our net premium during the three and nine months ended September 30, 2015, which follows the effective interest method, was approximately $0.1 million and $0.3 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations. Interest is payable semi-annually on our Senior Notes. Interest on the 2020 Senior Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year while interest on the 2022 Senior Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year. In connection with our Senior Notes due 2020 and our Senior Notes due 2022, we have interest payments due each year of approximately $31.1 million and $20.3 million, respectively.

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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, 2015 and December 31, 2014:

($ in Thousands)	September 30, 2015 (Unaudited)			December 31, 2014
8.875% Senior Notes Due 2020	$	350,000		$	350,000
6.25% Senior Notes Due 2022		325,000			325,000
Premium on Senior Notes, Net		2,442			2,725
Senior Line of Credit(a)		69,000			—
Capital Leases and Other Obligations(a)		800			1,427
Total Debt		747,242			679,152
Less Current Portion of Long-Term Debt		(668	)		(1,176	)
Total Long-Term Debt	$	746,574		$	677,976

^(a) The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and nine months ended September 30, 2015 and the year ended December 31, 2014, was approximately 1.8%, 1.7% and 2.2%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2015 and the year ended December 31, 2014, was approximately 4.2%, 5.8% and 4.0%, respectively.

The following is the principal maturity schedule for debt outstanding as of September 30, 2015:

2015	$	182
2016		590
2017		28
2018		—
2019		69,000
Thereafter		675,000
Total(a)	$	744,800

(a) Excludes $2.4 million net premium on Senior Notes.

8. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of September 30, 2015 and December 31, 2014, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, call protected swaps, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net.

We enter into the majority of our derivative arrangements with five counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 6, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. We received net cash settlements of $15.1 million and $39.2 million in relation to our commodity derivatives during the three and nine months ended September 30, 2015, respectively, and received net cash settlements of $3.0 million and paid net cash settlements of $4.2 million in relation to our commodity derivatives during the three and nine months ended September 30, 2014, respectively.

As of September 30, 2015, we had over 75.0% and 18.0% of our annualized oil production hedged through the remainder of 2015 and 2016, respectively, over 85.0% and 77.0% of our annualized natural gas production hedged through the remainder of 2015 and 2016, respectively, and over 59.0% and 41.0% of our annualized NGL production hedged through the remainder of 2015 and

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2016, respectively. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our oil and gas production.

Interest Rate Derivatives

We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of September 30, 2015 and December 31, 2014, we had $69.0 million and $0.0 outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $675.0 million of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.

As of September 30, 2015 and December 31, 2014, we did not have any interest rate derivatives outstanding. We utilize the mark-to-market accounting method to account for interest rate swap and swaptions. We recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Expense. During the three and nine months ended September 30, 2015, we received cash payments of approximately $0.1 million and $0.9 million, respectively, related to our previously-held interest rate swaps and swaptions.

The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, 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, 2015 and 2014:

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
($ in Thousands)	2015			2014		2015			2014
Oil	$	5,599		$	3,776	$	5,648		$	125
Natural Gas		12,013			6,857		28,649			77
NGLs		10,068			1,683		10,441			1,030
Refined Products		(180	)		—		(185	)		—
Interest Rate		1,149			—		934			1,083
Gain on Derivatives, Net	$	28,649		$	12,316	$	45,487		$	2,315

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net asset of approximately $36.8 million and $31.4 million at September 30, 2015 and December 31, 2014, respectively.

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Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2015 consisted of:

Period	Volume	Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2015 - Collars	75,000 Bbls	$	—	$	52.90	$	63.15	$	—		$	556
2015 - Three-Way Collars	150,000 Bbls		50.00		65.00		72.50		—			2,102
2016 - Collars	60,000 Bbls		—		53.75		63.81		—			467
2016 - Three-Way Collars	45,000 Bbls		50.00		65.00		70.00		—			423
2016 - Deferred Put Spreads	120,000 Bbls		50.00		65.00		—		—			531
	450,000 Bbls										$	4,079
Natural Gas
2015 - Swaps	4,375,000 Mcf	$	—	$	—	$	—	$	3.49		$	3,891
2015 - Swaptions	550,000 Mcf		—		—		—		3.53			453
2015 - Cap Swaps	1,950,000 Mcf		3.43		—		—		4.12			1,170
2015 - Three-Way Collars	2,200,000 Mcf		2.84		3.53		4.25		—			881
2015 - Put Spreads	650,000 Mcf		2.56		3.32		—		—			336
2015 - Calls	750,000 Mcf		—		—		4.15		—			—
2015 - Basis Swaps - Dominion South	2,300,000 Mcf		—		—		—		(0.82	)		101
2016 - Swaps	9,600,000 Mcf		—		—		—		3.45			6,207
2016 - Swaptions	0 Mcf		—		—		—		—			(305	)
2016 - Cap Swaps	3,600,000 Mcf		3.45		—		—		4.11			1,848
2016 - Collars	900,000 Mcf		—		3.20		4.04		—			427
2016 - Three-Way Collars	19,170,000 Mcf		2.51		3.22		3.99		—			4,620
2016 - Put Spreads	2,100,000 Mcf		2.25		3.00		—		—			172
2016 - Basis Swaps - Dominion South	12,510,000 Mcf		—		—		—		(0.90	)		(124	)
2017 - Swaps	960,000 Mcf		—		—		—		3.60			614
2017 - Cap Swaps	2,100,000 Mcf		3.34		—		—		4.07			1,122
2017 - Three-Way Collars	13,900,000 Mcf		2.38		3.09		4.02		—			2,670
2017 - Calls	840,000 Mcf		—		—		4.00		—			(93	)
2017 - Basis Swaps - Dominion South	4,550,000 Mcf		—		—		—		(0.83	)		(353	)
2017 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(15	)
2018 - Swaps	960,000 Mcf		—		—		—		3.60			614
2018 - Cap Swaps	1,800,000 Mcf		3.30		—		—		4.05			975
2018 - Three-Way Collars	5,475,000 Mcf		2.40		3.00		3.75		—			296
2018 - Calls	3,650,000 Mcf		—		—		4.25		—			(439	)
2018 - Basis Swaps - Dominion South	6,400,000 Mcf		—		—		—		(0.83	)		(515	)
2018 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(15	)
2019 - Basis Swaps - Dominion South	7,300,000 Mcf		—		—		—		(0.83	)		(592	)
2020 - Basis Swaps - Dominion South	7,320,000 Mcf		—		—		—		(0.83	)		(596	)
	145,110,000 Mcf										$	23,350
NGLs
2015 - C3+ NGL Swaps	387,000 Bbls	$	—	$	—	$	—	$	31.92		$	2,642
2015 - Ethane Swaps	102,600 Bbls		—		—		—		8.40			5
2016 - C3+ NGL Swaps	1,131,000 Bbls		—		—		—		32.76			6,848
2016 - Ethane Swaps	240,000 Bbls		—		—		—		8.82			54
2017 - C3+ NGL Swaps	132,000 Bbls		—		—		—		19.74			(38	)
	1,992,600 Bbls										$	9,511
Refined Product (Heating Oil)
2016 - Swaps	12,000 Bbls	$	—	$	—	$	—	$	84.00		$	(185	)
	12,000 Bbls										$	(185	)

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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, 2015 and December 31, 2014 is summarized below:

	September 30,			December 31,
($ in Thousands)	2015			2014
Short-Term Derivative Assets:
Crude Oil—Deferred Put Spread	$	398		$	1,413
Crude Oil—Call Protected Swap		—			1,227
Crude Oil—Three-Way Collars		2,384			4,596
Crude Oil—Collars		1,023			—
NGL—Swaps		7,847			6,181
Natural Gas—Swaps		8,462			4,522
Natural Gas—Cap Swaps		2,628			3,430
Natural Gas—Basis Swaps		661			2,815
Natural Gas—Three-Way Collars		4,427			5,081
Natural Gas—Swaption		454			—
Natural Gas—Collars		427			—
Natural Gas—Put Spread		483			—
Total Short-Term Derivative Assets	$	29,194		$	29,265
Long-Term Derivative Assets:
NGL—Swaps	$	1,790		$	—
Crude Oil—Deferred Put Spread		133			—
Crude Oil—Three-Way Collars		141			—
Natural Gas—Cap Swaps		2,487			1,617
Natural Gas—Swaps		2,864			1,554
Natural Gas—Basis Swaps		269			—
Natural Gas—Put Spread		25			—
Natural Gas—Three-Way Collars		4,040			1,733
Total Long-Term Derivative Assets	$	11,749		$	4,904
Total Derivative Assets	$	40,943		$	34,169
Short-Term Derivative Liabilities:
NGL—Swaps	$	(84	)	$	—
Refined Product—Swaps		(139	)		—
Natural Gas—Call		—			(74	)
Natural Gas—Swaption		(1	)		(154	)
Natural Gas—Put Spread		—			(193	)
Natural Gas—Basis Swaps		(539	)		—
Total Short - Term Derivative Liabilities	$	(763	)	$	(421	)
Long-Term Derivative Liabilities:
NGL—Swaps	$	(42	)	$	—
Refined Product—Swaps		(46	)		—
Natural Gas—Basis Swaps		(2,500	)		(1,281	)
Natural Gas—Swaption		(305	)		—
Natural Gas—Call		(532	)		(1,096	)
Total Long-Term Derivative Liabilities	$	(3,425	)	$	(2,377	)
Total Derivative Liabilities	$	(4,188	)	$	(2,798	)

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—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. 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 and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

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Level 3—Unobservable inputs that are supported by little or no market activity. 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, 2015, and December 31, 2014, 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, 2015 and December 31, 2014, 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, 2015 and December 31, 2014 are included in the table below.

	As of September 30, 2015
	Range (price per Mcf)	Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Basis Differential Forward Curve - Dominion South	($0.44) - ($1.39)	$	(0.80	)	$	(2,079	)
Natural Gas Basis Differential Forward Curve - Texas Gas	($0.12) - ($0.13)	$	(0.12	)	$	(30	)
	As of December 31, 2014
	Range (price per Mcf)	Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Basis Differential Forward Curve - Dominion South	($0.27) - ($1.39)	$	(0.84	)	$	1,341

The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three and nine months ended September 30, 2015 and for the year ended December 31, 2014, 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:

			Fair Value Measurements at September 30, 2015 Using:
($ in Thousands)	Total Carrying Value as of September 30, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	36,755	$	—	$	38,864	$	(2,109	)
			Fair Value Measurements at December 31, 2014 Using:
($ in Thousands)	Total Carrying Value as of December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	31,371	$	—	$	30,030	$	1,341

Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.

The value of our oil derivatives are comprised of three-way collar, call protected 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 values attributable to our oil derivatives as of September 30, 2015 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 swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread 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, 2015 are based on (i) the

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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, 2015 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 at fair value on a recurring basis using significant unobservable inputs (Level 3) during the nine months ended September 30, 2015 and 2014:

	Nine Months Ended September 30,
($ in Thousands)	2015			2014
Beginning Balance of Level 3	$	1,341		$	4,323
Changes in Fair Value		371			(4,343	)
Purchases		—			—
Settlements Received		(3,821	)		2,882
Ending Balance of Level 3	$	(2,109	)	$	2,862

Changes in fair value on our Level 3 commodity derivative contracts outstanding for the nine months ended September 30, 2015 and 2014, resulted in an increase of approximately $0.4 million and a decrease of approximately $4.3 million, respectively. This amount has been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.  

Future Abandonment Cost

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances.

Financial Instruments Not Recorded at Fair Value

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

	September 30, 2015				December 31, 2014
($ in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
8.875% Senior Notes due 2020	$	350,000	$	168,000	$	350,000	$	311,955
6.25% Senior Notes due 2022	$	325,000	$	135,688		325,000		241,313
Secured Line of Credit		69,000		69,000		—		—
Capital Leases and Other Obligations		800		781		1,427		1,393
Total	$	744,800	$	373,469	$	676,427	$	554,661

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

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 1 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.

Other Fair Value Measurements

During the nine months ended September 30, 2015, we recorded an other than temporary impairment of $264.7 million related to proved properties, unproved properties and equity method investments. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 2 within the fair value hierarchy. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

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:

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in Thousands)	2015			2014			2015			2014
Income (Expense) Benefit	$	20,037		$	(4,069	)	$	20,653		$	(13,839	)
Effective Tax Rate		13.4	%		42.0	%		6.4	%		38.6	%

For the nine months ended September 30, 2015, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due to the recording of a valuation allowance. As of September 30, 2015, we had a significant level of estimated future tax benefits that, given our past and future expectations of net losses, we do not expect to be able to fully utilize, thus limiting our ability to recognize future tax benefits. For the nine months ended September 30, 2014, our overall effective tax rate on pretax income from continuing operations was different than the statutory rate of 35% due primarily to state taxes and permanent items, including section 162(m) limitations.

Income tax payments made during the three and nine months ended September 30, 2015 and 2014 were negligible.  We received tax refunds during the nine months ended September 30, 2015 of approximately $0.5 million and $4.7 million during the nine months ended September 30, 2014.

10. CAPITAL STOCK

Common 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, 2015 and December 31, 2014, shares of common stock issued and outstanding totaled 54,975,151 and 54,174,763, respectively. 

Preferred Stock

On August 18, 2014, we completed a registered offering of 16,100 shares of 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (the “Series A Preferred Stock”) that are represented by 1,610,000 depositary shares. The net proceeds of the offering were approximately $155.0 million, after deducting underwriting discounts, commissions and other offering expenses. We utilized a portion of the net proceeds to fund our acquisition of assets from SWEPI, LP, an affiliate of Royal Dutch Shell, plc, and used the remaining proceeds to fund our capital expenditures program and for general corporate purposes.

The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on February 15, May 15, August 15 and November 15 of each year.

We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate

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from the most recent date upon which dividends were paid but will not bear interest. In February, May and August 2015, we paid quarterly cash dividends of $150.00 per share for the periods of November 15, 2014 to February 15, 2015, February 15, 2015 to May 15, 2015 and May 15, 2015 to August 15, 2015, respectively, each in the aggregate amount of $2.4 million.

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 one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.

Stock Options

During the nine-month period ended September 30, 2015, we issued 80,000 options to purchase shares of our common stock to three employees. We did not issue options to purchase shares of our common stock for the three months ending September 30, 2015 and the three and nine-month periods ended September 30, 2014. Stock-based compensation expense relating to stock options outstanding for the three and nine months ended September 30, 2015 and 2014 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. The intrinsic value of stock options exercised for the nine months ended September 30, 2014, was approximately $0.3 million. There were no stock options exercised for the nine months ended September 30, 2015.  There was no tax benefit for each of the nine-month periods ended September 30, 2015 and 2014.

A summary of the status of our issued and outstanding stock options as of September 30, 2015 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding At 9/30/15		Weighted-Average Exercise Price		Number Exercisable At 9/30/15		Weighted-Average Exercise Price
$	4.05		40,000	$	4.05		—	$	—
$	4.90		40,000	$	4.90		—	$	—
$	5.04		46,041	$	5.04		46,041	$	5.04
$	9.50		75,000	$	9.50		75,000	$	9.50
$	9.99		129,583	$	9.99		129,583	$	9.99
$	10.42		29,548	$	10.42		29,548	$	10.42
$	11.87		3,500	$	11.87		3,500	$	11.87
$	12.50		19,139	$	12.50		19,139	$	12.50
$	13.19		50,000	$	13.19		50,000	$	13.19
$	22.34		30,000	$	22.34		30,000	$	22.34
			462,811	$	9.76		382,811	$	10.86

The weighted average remaining contractual term for options outstanding at September 30, 2015 was 3.0 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at September 30, 2015 was 2.2 years and there was no aggregate intrinsic value. As of September 30, 2015, unrecognized compensation expense related to stock options was $0.1 million.  

Restricted Stock Awards

During the nine-month period ended September 30, 2015, the Compensation Committee approved the issuance of an aggregate of 1,361,497 shares of restricted common stock to 127 employees, one director and one non-employee contractor. During the nine-month period ended September 30, 2014, the Compensation Committee approved the issuance of an aggregate of 51,178 shares of restricted stock to 18 employees. Certain of our outstanding restricted stock awards granted in 2015, 2014 and 2013 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 over a three-year period.

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The weighted average fair value of the TSR awards granted as of September 30, 2015 and December 31, 2014 were $2.56 and $10.15 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, 2015			Year Ended December 31, 2014
Expected Dividend Yield		0.0	%		0.0	%
Risk-Free Interest Rate		1.0	%		0.8	%
Expected Volatility – Rex Energy		58.6	%		50.4	%
Expected Volatility – Peer Group	29.8%-85.0%			28.4%-65.7		%
Market Index		35.6	%		35.3	%
Expected Life	Three Years			Three Years

Compensation expense associated with restricted stock awards was negligible and $4.8 million for the three and nine-month periods ended September 30, 2015, respectively, and $1.6 million and $4.3 million for the three and nine-month periods ended September 30, 2014, respectively. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of approximately 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of September 30, 2015, total unrecognized compensation cost related to restricted common stock grants was approximately $4.3 million, which will be recognized over a weighted average period of 1.6 years.

A summary of the restricted stock activity for the nine months ended September 30, 2015 is as follows:

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2014		1,519,301		$	14.05
Awards		1,361,497			3.97
Forfeitures		(561,109	)		11.35
Vested		(439,346	)		8.33
Restricted stock awards, as of September 30, 2015		1,880,343		$	8.49

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.

Other than as set forth below, there have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.

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

In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when

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representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them. The plaintiffs seek the certification of a class and a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. On May 3, 2013, the Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings.

In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaints for both cases contain the same claims as those set forth in the Cardinale case. It is our understanding that these two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal.  Proceedings in the Billotte case have been consolidated with the Cardinale case; proceedings in the Meeker case are ongoing.

In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case.  In July 2015, the trial court denied plaintiffs’ motion for class certification.  Plaintiffs served notice of their appeal of that decision in August 2015 and filed the appeal in September 2015.  We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

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, 2015, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

At September 30, 2015, we had posted $10.7 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of September 30, 2015, 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, 2015, was approximately $0.3 million and $0.7 million, respectively, and $0.3 million and $0.8 million for the three and nine months ended September 30, 2014, respectively. Lease commitments by year for each of the next five years are presented in the table below:

($ in Thousands)
2015	$	282
2016		1,129
2017		1,143
2018		721
2019		721
Thereafter		180
Total	$	4,176

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Capacity Reservation

We have 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 in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $4.0 million in 2015, $19.8 million in 2016, $23.9 million in 2017, $23.9 million in 2018, $23.9 million in 2019 and $165.2 million thereafter, assuming our average net revenue interest in the region of approximately 54%. Charges incurred for unutilized processing capacity with MarkWest during the three and nine-month periods ended September 30, 2015 were negligible and $0.4 million, respectively, and were negligible during the three and nine-month periods ended September 30, 2014.

Operational Commitments

We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $0.6 million in 2015, $2.2 million in 2016 and $2.2 million in 2017, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations for the nine months ended September 30, 2015. Approximately $2.5 million of this amount was paid in January 2015 with the remaining amount due in January 2016. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $4.1 million in 2015 and $4.0 million in 2016, which would be partially offset by other working interest owners, which vary from well to well.

Natural Gas Gathering, Processing and Sales Agreements

During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $425.7 million.

For the three and nine months ended September 30, 2015 and 2014, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $20.9 million and $60.3 million in 2015, respectively, and $15.7 million and $36.1 million in 2014, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. During the three and nine months ended September 30, 2015, we incurred approximately $0.7 million and $2.8 million, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

($ in Thousands)	Total
2015	$	4,680
2016		25,007
2017		39,958
2018		41,544
2019		40,548
Thereafter		500,763
Total	$	652,500

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Pennsylvania Impact Fee

In 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. 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:

	<$2.25(a)		$2.26 - $2.99(a)		$3.00 - $4.99(a)		$5.00 - $5.99(a)		>$5.99(a)
Year One	$	40,200	$	45,300	$	50,300	$	55,300	$	60,400
Year Two	$	30,200	$	35,200	$	40,200	$	45,300	$	55,300
Year Three	$	25,200	$	30,200	$	30,200	$	40,200	$	50,300
Year 4 – 10	$	10,100	$	15,100	$	20,100	$	20,100	$	20,100
Year 11 – 15	$	5,000	$	5,000	$	10,100	$	10,100	$	10,100

^(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.

All fees owed are due on April 1 of each year. For the three and nine months ended September 30, 2015 and 2014, we recorded expense of approximately $0.8 million and $2.3 million in 2015, respectively, and $1.2 million and $2.5 million in 2014, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of September 30, 2015, approximately $2.5 million was accrued for the 2015 impact fees.

13. EARNINGS PER COMMON SHARE

Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For each of the three and nine months ended September 30, 2015, we excluded stock options to purchase 0.5 million shares due to our Net Loss from Continuing Operations. For each of the three and nine months ended September 30, 2014, we excluded stock options to purchase 0.3 million shares of our common stock due to the estimate of shares that would be repurchased using the treasury method. For each of the three and nine months ended September 30, 2015, we excluded performance-based restricted stock of 1.1 million shares due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 11, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). For the three and nine-month periods ended September 30, 2014, we excluded performance-based restricted stock of 0.4 million shares and 0.7 million shares, respectively, due to performance metrics that have not yet been attained. We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For each of the three and nine months ended September 30, 2015, we excluded the assumed conversion of preferred stock equating to approximately 8.9 million shares due to our Net Loss from Continuing Operations. 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,
Numerator:	2015			2014		2015			2014
Net Income (Loss) From Continuing Operations	$	(129,293	)	$	5,619	$	(301,145	)	$	22,019
Net Income From Discontinued Operations, Less Noncontrolling Interests		34,618			75		35,904			623
Less: Preferred Stock Dividends		(2,415	)		—		(7,245	)		—
Net Income (Loss) Attributable to Common Shareholders	$	(97,090	)	$	5,694	$	(272,486	)	$	22,642
Denominator:
Weighted Average Common Shares Outstanding - Basic		53,936			53,214		53,748			53,493
Effect of Dilutive Securities:
Employee Stock Options		—			111		—			134
Employee Performance-Based Restricted Stock Awards		—			485		—			218
Effect of Assumed Conversions of Preferred Stock		—			4,181		—			1,409
Weighted Average Common Shares Outstanding - Diluted		53,936			57,991		53,748			55,254
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Income (Loss) From Continuing Operations	$	(2.44	)	$	0.11	$	(5.74	)	$	0.41
— Net Income From Discontinued Operations		0.64			0.00		0.67			0.01
— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(1.80	)	$	0.11	$	(5.07	)	$	0.42
Diluted — Net Income (Loss) From Continuing Operations	$	(2.44	)	$	0.10	$	(5.74	)	$	0.40
— Net Income From Discontinued Operations		0.64			0.00		0.67			0.01
— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(1.80	)	$	0.10	$	(5.07	)	$	0.41

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14. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our Appalachian Basin operations. Our investment in RW Gathering totaled $17.9 million as of December 31, 2014, and was recorded on our Consolidated Balance Sheets as Equity Method Investments. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering (for additional information, see Note 15, Impairment Expense, to our Consolidated Financial Statements). We did not make any capital contributions to RW Gathering during the first nine months of 2015 and 2014. RW Gathering recorded net losses from continuing operations of $0.5 million and $1.5 million during the three and nine-month periods ended September 30, 2015, respectively, as compared to losses of $0.5 million and $1.5 million for the comparable periods in 2014, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Historically, we have recorded our share of the net losses on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued applying the equity method of accounting for our share of the net losses due to our investment being reduced to zero.

During the three and nine-month periods ended September 30, 2015, we incurred approximately $0.2 million and $0.5 million, respectively, as compared to $0.2 million and $0.5 million for the three and nine-month periods ended September 30, 2014, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of September 30, 2015 and December 31, 2014, there were no receivables due from RW Gathering to us.

15. IMPAIRMENT EXPENSE

For the three and nine months ended September 30, 2015, impairment expenses incurred were approximately $139.8 million and $264.7 million, respectively, while impairment expenses incurred during the three and nine months ended September 30, 2014 were negligible. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first nine months of 2015 included proved property impairments of approximately $211.4 million, with approximately $170.5 million attributable to unconventional assets in the Appalachian Basin, including $17.5 million related to our equity method investment in RW Gathering, and $40.0 million attributable to our conventional oil properties in the Illinois Basin. The remaining proved property impairment expense is related to our conventional dry gas assets in the Appalachian Basin. In addition to the proved properties, we also incurred unproved property impairments of approximately $38.5 million related to unconventional assets in the Appalachian Basin and $14.8 million related to our conventional oil properties in the Illinois Basin.The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. The primary reason for the decrease in estimated future cash flows of our assets is attributable to the continued depression of current and estimated future commodity prices as of September 30, 2015. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices continue to decline, which may result in our incurrence of additional impairment expense. As of September 30, 2015, we continued to carry the costs of undeveloped properties of approximately $288.8 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

16. EXPLORATION EXPENSE

For the three and nine months ended September 30, 2015, we incurred approximately $0.8 million and $2.2 million, respectively, in exploration expenses as compared to $1.5 million and $4.9 million in exploration expenses for the same periods in 2014, respectively. Approximately $0.8 million of the expense incurred in 2015 was due to geological and geophysical type expenditures, $1.0 million was due to the payment of delay rentals in the Appalachian Basinand $0.4 million was due to dry hole expense for non-operated properties located in the Illinois Basin. Approximately $3.3 million of the expense incurred in 2014 was due to geological and geophysical type expenditures. An additional $1.2 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin.

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of September 30, 2015, we had an aggregate of $675.0 million of outstanding Senior Notes, 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 guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy

25

Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of September 30, 2015:

● 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, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, 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, 2015, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014, the condensed consolidating statements of operations for each of the three and nine-month periods ended September 30, 2015 and 2014, and the condensed consolidating statements of cash flows for each of the nine-month periods ended September 30, 2015 and 2014.

26

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF SEPTEMBER 30, 2015

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,145		$	—		$	5		$	—		$	3,150
Accounts Receivable		29,054			37			47			—			29,138
Taxes Receivable		—			—			19			—			19
Short-Term Derivative Instruments		29,194			—			—			—			29,194
Inventory, Prepaid Expenses and Other		2,031			—			138			—			2,169
Total Current Assets		63,424			37			209			—			63,670
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,208,437			771			—			(6,952	)		1,202,256
Unevaluated Oil and Gas Properties		288,800			—			—			—			288,800
Other Property and Equipment		45,035			895			—			—			45,930
Wells and Facilities in Progress		125,207			234			—			(288	)		125,153
Pipelines		16,412			—			—			(2,137	)		14,275
Total Property and Equipment		1,683,891			1,900			—			(9,377	)		1,676,414
Less: Accumulated Depreciation, Depletion and Amortization		(633,955	)		(860	)		—			2,838			(631,977	)
Net Property and Equipment		1,049,936			1,040			—			(6,539	)		1,044,437
Deferred Financing Costs and Other Assets—Net		2,490			—			13,781			—			16,271
Long-Term Deferred Tax Asset		—			—			10,648			—			10,648
Intercompany Receivables		—			—			1,043,565			(1,043,565	)		—
Investment in Subsidiaries – Net		(1,907	)		—			243,331			(241,424	)		—
Long-Term Derivative Instruments		11,749			—			—			—			11,749
Total Assets	$	1,125,692		$	1,077		$	1,311,534		$	(1,291,528	)	$	1,146,775
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	29,551		$	—		$	—		$	—		$	29,551
Current Maturities of Long-Term Debt		668			—			—			—			668
Accrued Liabilities		35,471			152			16,341			—			51,964
Short-Term Derivative Instruments		763			—			—			—			763
Current Deferred Tax Liability		—			—			10,648			—			10,648
Total Current Liabilities		66,453			152			26,989			—			93,594
Long-Term Derivative Instruments		3,425			—			—			—			3,425
Senior Secured Line of Credit and Other Long-Term Debt		132			—			69,000			—			69,132
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
6.25% Senior Notes Due 2022		—			—			325,000			—			325,000
Premium on Senior Notes – Net		—			—			2,442			—			2,442
Other Deposits and Liabilities		3,372			—			—			—			3,372
Future Abandonment Cost		40,685			60			—			—			40,745
Intercompany Payables		1,043,090			475			—			(1,043,565	)		—
Total Liabilities		1,157,157			687			773,431			(1,043,565	)		887,710
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			—			618,164			(173,063	)		622,245
Accumulated Earnings (Deficit)		(208,609	)		390			(80,116	)		(74,900	)		(363,235	)
Total Stockholders’ Equity		(31,465	)		390			538,103			(247,963	)		259,065
Total Liabilities and Stockholders’ Equity	$	1,125,692		$	1,077		$	1,311,534		$	(1,291,528	)	$	1,146,775

27

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2015

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	37,429		$	136		$	—		$	—		$	37,565
Other Revenue		8			—			—			—			8
TOTAL OPERATING REVENUE		37,437			136			—			—			37,573
OPERATING EXPENSES
Production and Lease Operating Expense		30,565			51			—			—			30,616
General and Administrative Expense		5,434			12			(70	)		—			5,376
Gain on Disposal of Asset		(230	)		—			—			—			(230	)
Impairment Expense		139,837			1,003			—			(1,030	)		139,810
Exploration Expense		628			179			—			—			807
Depreciation, Depletion, Amortization and Accretion		27,370			27			—			(273	)		27,124
Other Operating Income		183			—			—			—			183
TOTAL OPERATING EXPENSES		203,787			1,272			(70	)		(1,303	)		203,686
INCOME (LOSS) FROM OPERATIONS		(166,350	)		(1,136	)		70			1,303			(166,113	)
OTHER INCOME (EXPENSE)
Interest Expense		(53	)		—			(11,833	)		—			(11,886	)
Gain on Derivatives, Net		27,499			—			1,150			—			28,649
Other Income		20			—			—			—			20
Loss From Equity Method Investments		—			—			—			—			—
Income (Loss) From Equity in Consolidated Subsidiaries		(1,063	)		1,063			(86,517	)		86,517			—
TOTAL OTHER INCOME (EXPENSE)		26,403			1,063			(97,200	)		86,517			16,783
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME    TAX		(139,947	)		(73	)		(97,130	)		87,820			(149,330	)
Income Tax Benefit		17,510			74			2,453			—			20,037
INCOME (LOSS) FROM CONTINUING OPERATIONS		(122,437	)		1			(94,677	)		87,820			(129,293	)
Income From Discontinued Operations, Net of Income Tax		—			34,557			—			60			34,617
Net Income (Loss)		(122,437	)		34,558			(94,677	)		87,880			(94,676	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			(1	)		—			—			(1	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(122,437	)	$	34,559		$	(94,677	)	$	87,880		$	(94,675	)
Preferred Stock Dividends		—			—			2,415			—			2,415
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(122,437	)	$	34,559		$	(97,092	)	$	87,880		$	(97,090	)

28

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2015

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	136,981		$	456		$	—		$	—		$	137,437
Other Revenue		30			—			—			—			30
TOTAL OPERATING REVENUE		137,011			456			—			—			137,467
OPERATING EXPENSES
Production and Lease Operating Expense		90,164			146			—			—			90,310
General and Administrative Expense		18,587			45			4,875			—			23,507
Gain on Disposal of Asset		(465	)		—			—			—			(465	)
Impairment Expense		264,693			1,014			—			(1,030	)		264,677
Exploration Expense		1,972			275			—			(5	)		2,242
Depreciation, Depletion, Amortization and Accretion		83,427			133			—			(772	)		82,788
Other Operating Expense		5,304			—			—			—			5,304
TOTAL OPERATING EXPENSES		463,682			1,613			4,875			(1,807	)		468,363
INCOME (LOSS) FROM OPERATIONS		(326,671	)		(1,157	)		(4,875	)		1,807			(330,896	)
OTHER INCOME (EXPENSE)
Interest Expense		(195	)		—			(35,902	)		—			(36,097	)
Gain on Derivatives, Net		44,553			—			934			—			45,487
Other Income		119			—			—			—			119
Loss From Equity Method Investments		(411	)		—			—			—			(411	)
Income (Loss) From Equity in Consolidated Subsidiaries		(1,083	)		1,083			(227,955	)		227,955			—
TOTAL OTHER INCOME (EXPENSE)		42,983			1,083			(262,923	)		227,955			9,098
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME    TAX		(283,688	)		(74	)		(267,798	)		229,762			(321,798	)
Income Tax Benefit		18,022			74			2,557			—			20,653
INCOME (LOSS) FROM CONTINUING OPERATIONS		(265,666	)		—			(265,241	)		229,762			(301,145	)
Income (Loss) From Discontinued Operations, Net of Income Tax		—			39,341			—			(1,192	)		38,149
Net Income (Loss)		(265,666	)		39,341			(265,241	)		228,570			(262,996	)
Net Income (Loss) Attributable to Noncontrolling Interests of Discontinued Operations		—			2,245			—			—			2,245
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(265,666	)	$	37,096		$	(265,241	)	$	228,570		$	(265,241	)
Preferred Stock Dividends		—			—			7,245			—			7,245
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(265,666	)	$	37,096		$	(272,486	)	$	228,570		$	(272,486	)

29

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2015

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(265,666	)	$	39,341		$	(265,241	)	$	228,570		$	(262,996	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating    Activities
Loss From Equity Method Investments		411			—			—			—			411
Non-Cash Expenses (Income)		(120	)		(334	)		6,145			—			5,691
Depreciation, Depletion, Amortization and Accretion		83,427			3,205			—			(3,766	)		82,866
(Gain) on Derivatives		(44,553	)		—			(934	)		—			(45,487	)
Cash Settlements of Derivatives		39,168			—			934			—			40,102
Dry Hole Expense		199			275			—			(6	)		468
Gain on Sale of Asset		(465	)		(44	)		—			—			(509	)
Gain on Sale of Water Solutions		—			—			(57,014	)		—			(57,014	)
Impairment Expense		264,693			1,014			—			(1,030	)		264,677
Changes in operating assets and liabilities
Accounts Receivable		14,602			(478	)		429			(2,538	)		12,015
Inventory, Prepaid Expenses and Other Assets		1,342			(142	)		(108	)		—			1,092
Accounts Payable and Accrued Liabilities		(27,935	)		(4,816	)		4,110			2,538			(26,103	)
Other Assets and Liabilities		(1,748	)		(73	)		27			—			(1,794	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		63,355			37,948			(311,652	)		223,768			13,419
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		79,071			(38,532	)		184,393			(224,932	)		—
Proceeds from Joint Venture Acreage Management		54			—			—			—			54
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		9,557			559			66,135			—			76,251
Proceeds from Joint Venture		16,611			—			—			—			16,611
Acquisitions of Undeveloped Acreage		(26,232	)		(279	)		—			—			(26,511	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(156,432	)		(7,939	)		—			1,164			(163,207	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(77,371	)		(46,191	)		250,528			(223,768	)		(96,802	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			35,813			151,000			—			186,813
Repayments of Long-Term Debt and Lines of Credit		—			(26,335	)		(82,000	)		—			(108,335	)
Repayments of Loans and Other Long-Term Debt		(817	)		(520	)		—			—			(1,337	)
Debt Issuance Costs		—			(3	)		(626	)		—			(629	)
Dividends Paid		—			—			(7,245	)		—			(7,245	)
Distributions by the Partners of Consolidated Subsidiaries		—			(830	)		—			—			(830	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(817	)		8,125			61,129			—			68,437
NET INCREASE (DECREASE) IN CASH		(14,833	)		(118	)		5			—			(14,946	)
CASH – BEGINNING		17,978			118			—			—			18,096
CASH - ENDING	$	3,145		$	—		$	5		$	—		$	3,150

30

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF DECEMBER 31, 2014

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	17,978		$	—		$	—		$	—		$	17,978
Accounts Receivable		43,726			210			—			—			43,936
Taxes Receivable		—			—			504			—			504
Short-Term Derivative Instruments		29,265			—			—			—			29,265
Assets Held for Sale		—			36,794			—			(2,537	)		34,257
Inventory, Prepaid Expenses and Other		3,374			—			29			—			3,403
Total Current Assets		94,343			37,004			533			(2,537	)		129,343
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,084,332			467			—			(5,760	)		1,079,039
Unevaluated Oil and Gas Properties		321,708			705			—			—			322,413
Other Property and Equipment		45,466			895			—			—			46,361
Wells and Facilities in Progress		127,759			456			—			(560	)		127,655
Pipelines		17,555			—			—			(1,898	)		15,657
Total Property and Equipment		1,596,820			2,523			—			(8,218	)		1,591,125
Less: Accumulated Depreciation, Depletion and Amortization		(367,224	)		(730	)		—			1,037			(366,917	)
Net Property and Equipment		1,229,596			1,793			—			(7,181	)		1,224,208
Deferred Financing Costs and Other Assets—Net		2,421			—			14,649			—			17,070
Equity Method Investments		17,895			—			—			—			17,895
Long-Term Deferred Tax Asset		—			—			8,301			—			8,301
Intercompany Receivables		—			—			951,025			(951,025	)		—
Investment in Subsidiaries – Net		4,161			1,541			258,448			(264,150	)		—
Long-Term Derivative Instruments		4,904			—			—			—			4,904
Total Assets	$	1,353,320		$	40,338		$	1,232,956		$	(1,224,893	)	$	1,401,721
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	55,877		$	—		$	—		$	(2,537	)	$	53,340
Current Maturities of Long-Term Debt		1,176			—			—			—			1,176
Accrued Liabilities		46,783			571			12,124			—			59,478
Short-Term Derivative Instruments		421			—			—			—			421
Current Deferred Tax Liability		—			—			8,301			—			8,301
Liabilities Related to Assets Held for Sale		—			25,115			—			—			25,115
Total Current Liabilities		104,257			25,686			20,425			(2,537	)		147,831
Long-Term Derivative Instruments		2,377			—			—			—			2,377
Senior Secured Line of Credit and Other Long-Term Debt		251			—			—			—			251
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
6.25% Senior Notes Due 2022		—			—			325,000			—			325,000
Premium (Discount) on Senior Notes – Net		—			—			2,725			—			2,725
Other Deposits and Liabilities		4,018			—			—			—			4,018
Future Abandonment Cost		38,097			49			—			—			38,146
Intercompany Payables		947,114			3,911			—			(951,025	)		—
Total Liabilities		1,096,114			29,646			698,150			(953,562	)		870,348
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			79,743			617,826			(256,887	)		617,826
Accumulated Earnings (Deficit)		80,062			(69,253	)		(83,075	)		(18,483	)		(90,749	)
Rex Energy Stockholders’ Equity		257,206			10,490			534,806			(275,370	)		527,132
Noncontrolling Interests		—			202			—			4,039			4,241
Total Stockholders’ Equity		257,206			10,692			534,806			(271,331	)		531,373
Total Liabilities and Stockholders’ Equity	$	1,353,320		$	40,338		$	1,232,956		$	(1,224,893	)	$	1,401,721

31

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	73,343		$	105		$	—		$	—		$	73,448
Other Revenue		18			—			—			—			18
TOTAL OPERATING REVENUE		73,361			105			—			—			73,466
OPERATING EXPENSES
Production and Lease Operating Expense		27,670			4			—			—			27,674
General and Administrative Expense		7,709			24			1,555			—			9,288
Loss on Disposal of Asset		174			—			—			—			174
Impairment Expense		—			—			—			—			—
Exploration Expense		1,452			10			—			—			1,462
Depreciation, Depletion, Amortization and Accretion		26,536			36			—			(197	)		26,375
Other Operating Expense		(24	)		—			—			—			(24	)
TOTAL OPERATING EXPENSES		63,517			74			1,555			(197	)		64,949
INCOME (LOSS) FROM OPERATIONS		9,844			31			(1,555	)		197			8,517
OTHER INCOME (EXPENSE)
Interest Expense		(56	)		—			(10,890	)		—			(10,946	)
Gain (Loss) on Derivatives, Net		12,316			—			—			—			12,316
Other Expense		3			—			—			—			3
Loss From Equity Method Investments		(202	)		—			—			—			(202	)
Income (Loss) From Equity in Consolidated Subsidiaries		18			(18	)		12,840			(12,840	)		—
TOTAL OTHER INCOME (EXPENSE)		12,079			(18	)		1,950			(12,840	)		1,171
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE    INCOME TAX		21,923			13			395			(12,643	)		9,688
Income Tax (Expense) Benefit		(8,853	)		(515	)		5,299			—			(4,069	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		13,070			(502	)		5,694			(12,643	)		5,619
Loss From Discontinued Operations, Net of Income Tax		—			1,836			—			(866	)		970
Net Income (Loss)		13,070			1,334			5,694			(13,509	)		6,589
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			895			—			—			895
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	13,070		$	439		$	5,694		$	(13,509	)	$	5,694
Preferred Stock Dividends		—			—			—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	13,070		$	439		$	5,694		$	(13,509	)	$	5,694

32

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	227,547		$	103		$	—		$	—		$	227,650
Other Revenue		92			—			—			—			92
TOTAL OPERATING REVENUE		227,639			103			—			—			227,742
OPERATING EXPENSES
Production and Lease Operating Expense		69,328			10			—			—			69,338
General and Administrative Expense		22,811			72			4,296			—			27,179
Loss on Disposal of Asset		468			—			—			—			468
Impairment Expense		41			—			—			—			41
Exploration Expense		4,877			13			—			—			4,890
Depreciation, Depletion, Amortization and Accretion		66,812			109			—			(467	)		66,454
Other Operating Expense		3			—			—			—			3
TOTAL OPERATING EXPENSES		164,340			204			4,296			(467	)		168,373
INCOME (LOSS) FROM OPERATIONS		63,299			(101	)		(4,296	)		467			59,369
OTHER INCOME (EXPENSE)
Interest Expense		(86	)		—			(25,150	)		—			(25,236	)
Gain on Derivatives, Net		1,232			—			1,083			—			2,315
Other Income		20			—			—			—			20
Loss From Equity Method Investments		(610	)		—			—			—			(610	)
Income (Loss) From Equity in Consolidated Subsidiaries		(65	)		65			39,667			(39,667	)		—
TOTAL OTHER INCOME (EXPENSE)		491			65			15,600			(39,667	)		(23,511	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		63,790			(36	)		11,304			(39,200	)		35,858
Income Tax (Expense) Benefit		(22,964	)		(2,214	)		11,339			—			(13,839	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		40,826			(2,250	)		22,643			(39,200	)		22,019
Income (Loss) From Discontinued Operations, Net of Income Taxes		—			7,597			—			(3,634	)		3,963
NET INCOME (LOSS)		40,826			5,347			22,643			(42,834	)		25,982
Net Income Attributable to Noncontrolling Interests		—			3,340			—			—			3,340
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	40,826		$	2,007		$	22,643		$	(42,834	)	$	22,642

33

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2014

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	40,826		$	5,347		$	22,643		$	(42,834	)	$	25,982
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by    Operating Activities
Loss From Equity Method Investments		610			—			—			—			610
Non-Cash Expenses		(203	)		233			5,116			—			5,146
Depreciation, Depletion, Amortization and Accretion		66,812			2,671			—			(469	)		69,014
Deferred Income Tax Expense (Benefit)		22,964			2,967			(11,339	)		—			14,592
Gain on Derivatives		(1,232	)		—			(1,083	)		—			(2,315	)
Cash Settlements of Derivatives		(4,209	)		—			878			—			(3,331	)
Dry Hole Expense		237			—			—			—			237
(Gain) Loss on Sale of Asset		469			(84	)		—			—			385
Impairment Expense		41			—			—			—			41
Changes in operating assets and liabilities
Accounts Receivable		(9,510	)		(3,455	)		4,685			(1,574	)		(9,854	)
Inventory, Prepaid Expenses and Other Assets		(812	)		(209	)		(17	)		—			(1,038	)
Accounts Payable and Accrued Liabilities		22,975			(1,007	)		12,518			1,574			36,060
Other Assets and Liabilities		(1,942	)		(24	)		—			—			(1,966	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		137,026			6,439			33,401			(43,303	)		133,563
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		408,192			248			(448,109	)		39,669			—
Proceeds from Joint Venture Acreage Management		210			—			—			—			210
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		248			164			—			—			412
Acquisitions of Undeveloped Acreage		(152,765	)		(863	)		—			—			(153,628	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(305,672	)		(8,315	)		—			3,634			(310,353	)
NET CASH USED IN INVESTING ACTIVITIES		(49,787	)		(8,766	)		(448,109	)		43,303			(463,359	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			22,041			171,000			—			193,041
Repayments of Long-Term Debt and Lines of Credit		—			(18,146	)		(230,000	)		—			(248,146	)
Repayments of Loans and Other Notes Payable		(1,323	)		(675	)		—			—			(1,998	)
Proceeds from Senior Notes, Net of Discounts and Premiums		—			—			325,000			—			325,000
Debt Issuance Costs		—			(7	)		(6,724	)		—			(6,731	)
Proceeds from the Issuance of Preferred Stock, Net		—			—			155,011			—			155,011
Proceeds from Exercise of Stock Options		—			—			421			—			421
Distributions by the Partners of Consolidated Subsidiaries		—			(1,080	)		—			—			(1,080	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,323	)		2,133			414,708			—			415,518
NET INCREASE IN CASH		85,916			(194	)		—			—			85,722
CASH – BEGINNING		1,386			509			5			—			1,900
CASH - ENDING	$	87,302		$	315		$	5		$	—		$	87,622

34

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, 2014 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

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 the Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) 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. We are headquartered in State College, Pennsylvania, and have regional offices in Bridgeport, Illinois; Cranberry, Pennsylvania; and Carrollton, Ohio.

We believe the outlook for our business is favorable despite the continued uncertainty of oil and gas prices. Our resource base, risk management, including an active hedging program, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating areas. We continue to focus on maintaining financial flexibility while pursuing an active, technology-driven drilling program to develop and maximize the value of our existing acreage as market conditions continue to evolve.

However, a continued prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserves, and may result in write-downs of the carrying values of our oil and natural gas properties and revisions to our capital budget or development program. We discuss these matters in further detail under, among other places, “Commodity Prices,” “Impairment Expense,” “Capital Resources and Liquidity,” and “Volatility of Oil, NGL and Natural Gas Prices” below as well as in Note 15, “Impairment Expense”, to our Consolidated Financial Statements.

We have historically divided our operations into two principal business segments, exploration and production and field services. During the third quarter of 2015, we sold Water Solutions Holdings, LLC (“Water Solutions”) and its related subsidiaries, which accounted for the majority of our field services segment. We view the activities of Water Solutions as non-core to our exploration and production operations and used the proceeds from the sale to fund development within our exploration and production operations. The sale of Water Solutions closed in July 2015, and we received approximately $66.1 million in proceeds for our 60% interest, net of customary selling expenses. Unless otherwise noted, information presented in management’s discussion and analysis are for continuing operations.

2015 Activity

During the three and nine months ended September 30, 2015, we produced 16,778 MMcfe and 51,081 MMcfe, respectively, in the Appalachian Basin. In the Illinois Basin, we produced 183 MBbls and 545 MBbls during the three and nine months ended September 30, 2015, respectively. Overall, our production for the three and nine months ended September 30, 2015 averaged 194,286 Mcfe per day and 199,096 Mcfe per day, respectively. As of September 30, 2015, we had 14.0 gross (10.3 net) wells drilled and awaiting completion and nine gross (six net) wells resting or awaiting pipeline connection. Our drilling and completion activity for the period indicated in each of our regions is set forth in the table below.

35

Three Months Ended September 30, 2015 and 2014

	Three Months Ended September 30, 2015
	Wells Drilled				Wells Completed				Wells Placed In Service
	Gross		Net		Gross		Net		Gross		Net
Appalachian Basin		10.0		6.9		11.0		5.6		9.0		3.8
Illinois Basin		—		—		—		—		—		—
Total		10.0		6.9		11.0		5.6		9.0		3.8
	Three Months Ended September 30, 2014
	Wells Drilled				Wells Completed				Wells Placed In Service
	Gross		Net		Gross		Net		Gross		Net
Appalachian Basin		16.0		11.5		13.0		9.1		20.0		16.7
Illinois Basin		4.0		4.0		6.0		6.0		6.0		6.0
Total		20.0		15.5		19.0		15.1		26.0		22.7

Nine Months Ended September 30, 2015 and 2014

	Nine Months Ended September 30, 2015
	Wells Drilled				Wells Completed				Wells Placed In Service
	Gross		Net		Gross		Net		Gross		Net
Appalachian Basin		28.0		18.1		26.0		12.7		26.0		13.4
Illinois Basin		—		—		5.0		5.0		5.0		5.0
Total		28.0		18.1		31.0		17.7		31.0		18.4
	Nine Months Ended September 30, 2014
	Wells Drilled				Wells Completed				Wells Placed In Service
	Gross		Net		Gross		Net		Gross		Net
Appalachian Basin		38.0		28.8		41.0		32.2		37.0		29.4
Illinois Basin		6.0		6.0		28.0		28.0		28.0		28.0
Total		44.0		34.8		69.0		60.2		65.0		57.4

Commodity Prices

Our development plans are sensitive to current and projected commodity prices which have been and are expected to continue to be volatile. Our realized price, before derivative settlements, for oil during the three and nine months ended September 30, 2015, averaged approximately $40.01 per barrel and $43.04 per barrel, respectively, as compared to $90.00 per barrel and $93.28 per barrel for the same periods in 2014, respectively. Our realized price, before derivative settlements, for natural gas during the three and nine months ended September 30, 2015, averaged approximately $1.74 per Mcf and $1.99 per Mcf, respectively, as compared to $2.53 per Mcf and $3.79 per Mcf for the same periods in 2014, respectively. Our realized price, before derivative settlements, for C3+ NGLs during the three and nine months ended September 30, 2015, averaged approximately $10.17 per barrel and $15.83 per barrel, respectively, as compared to $46.49 per barrel and $50.74 per barrel for the same periods in 2014, respectively.

For the three and nine months ended September 30, 2015, we recorded impairment expense of approximately $139.8 million and $264.7 million, respectively. Further decreases in commodity prices will decrease our oil, NGL and natural gas revenues and could reduce the amount of oil, NGL and natural gas reserves that we can economically produce. A prolonged period of depressed commodity prices or further declines in projected future commodity prices could require additional write-downs of the carrying values of our properties.

Because we follow the successful efforts method of accounting our impairment tests are largely based on estimates of future commodity prices, changes in development and operating costs, taxes, operational efficiencies, changes in technology and access to capital, which makes predicting any future write-downs difficult and uncertain. In an effort to quantify the impact of continued low commodity pricing levels or further declines in future prices, we offer the following: as of September 30, 2015, approximately 70% of our evaluated and unevaluated oil and natural gas properties were located in our Butler Marcellus operating area. Estimated future cash flows for these properties as of September 30, 2015, exceeded net book value by over 100%, indicating that substantial further

36

decreases in commodity prices combined with a lack of access to capital or a detrimental change to costs or operating efficiencies, would need to occur in order for us to experience a write-down. Our remaining evaluated and unevaluated properties outside of the Butler Marcellus operating area are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated and unevaluated properties total approximately $263.7 million.

ArcLight Capital Partners, LLC Joint Venture

On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight will participate and fund 35.0% of the estimated well costs for the designated wells. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. The remaining proceeds will be received as additional wells are drilled and completed. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us, leaving ArcLight with a 17.5% working interest. ArcLight also has the option to participate in the development of 17 additional wells in 2016; if ArcLight exercises this option, Arclight will participate and fund 20% of the estimated well costs for the designated wells in return for a 20% working interest.  If ArcLight elects to participate in the 2016 wells, the wells will also be subject to certain return on investment and internal rate of return thresholds, which, once met, will revert 50% of ArcLight’s working interest in the wells back to us. As of September 30, 2015, ArcLight had paid approximately $24.9 million for their interest in wells that have been drilled or are in the process of being drilled.

Water Solutions Divestiture

On June 18, 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions and its subsidiaries, of which we own a 60.0% interest. The sale closed in July 2015 and resulted in net proceeds to us of approximately $66.1 million, after customary selling expenses. Approximately $1.0 million of the gross proceeds have been placed in escrow pending any post-closing adjustments. We expect to receive our portion of the gross proceeds during the fourth quarter of 2015. We used the initial proceeds to pay down our revolving line of credit and for general corporate purposes.

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, 2015 and 2014.

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2015		2014		2015		2014
Production:
Oil and Condensate (Bbls)		268,775		306,088		891,054		808,357
Natural Gas (Mcf)		10,731,248		9,846,693		34,160,329		25,681,687
C3+ NGLs (Bbls)		498,256		411,655		1,571,358		1,042,378
Ethane (Bbls)		423,478		242,557		903,086		256,505
Total (Mcfe)(a)		17,874,302		15,608,493		54,353,317		38,325,127
Average daily production:
Oil and Condensate (Bbls)		2,921		3,327		3,264		2,961
Natural Gas (Mcf)		116,644		107,029		125,129		94,072
C3+ NGLs (Bbls)		5,416		4,475		5,756		3,818
Ethane (Bbls)		4,603		2,636		3,308		940
Total (Mcfe)(a)		194,286		169,658		199,096		140,385
Average sales price(b):
Oil and Condensate (per Bbl)	$	40.01	$	90.00	$	43.04	$	93.28
Natural Gas (per Mcf)	$	1.74	$	2.53	$	1.99	$	3.79
C3+ NGLs (per Bbl)	$	10.17	$	46.49	$	15.83	$	50.74
Ethane (per Bbl)	$	7.22	$	7.76	$	6.82	$	7.67
Total (per Mcfe)(a)	$	2.10	$	4.71	$	2.53	$	5.94
Average NYMEX prices(c):
Oil (per Bbl)	$	46.43	$	97.17	$	51.00	$	99.61
Natural Gas (per Mcf)	$	2.73	$	3.97	$	2.76	$	4.43

(a) Oil, Ethane and C3+ 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.

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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, 2015 and 2014.

	Production and Revenue by Basin
	For Three Months Ended September 30,				For Nine Months Ended September 30,
	2015		2014		2015		2014
Appalachian
Revenue – Natural Gas(a)	$	18,684,131	$	24,882,893	$	68,057,175	$	97,381,007
Volumes (Mcf)		10,731,248		9,846,693		34,160,329		25,681,687
Average Price	$	1.74	$	2.53	$	1.99	$	3.79
Revenue – Condensate (a)	$	2,836,869	$	7,402,341	$	12,257,384	$	17,108,064
Volumes (Bbl)		85,988		92,457		345,726		203,961
Average Price	$	32.99	$	80.06	$	35.45	$	83.88
Revenue – C3+ NGLs(a)	$	5,068,550	$	19,135,861	$	24,871,939	$	52,895,161
Volumes (Bbl)		498,256		411,655		1,571,358		1,042,378
Average Price	$	10.17	$	46.49	$	15.83	$	50.74
Revenue – Ethane(a)	$	3,058,408	$	1,882,916	$	6,157,611	$	1,966,642
Volumes (Bbl)		423,478		242,557		903,086		256,505
Average Price	$	7.22	$	7.76	$	6.82	$	7.67
Average Production Cost per Mcfe(b)	$	1.44	$	1.33	$	1.39	$	1.28
Illinois
Revenue – Oil(a)	$	7,916,740	$	20,144,217	$	26,092,485	$	58,299,255
Volumes (Bbl)		182,787		213,632		545,328		604,396
Average Price	$	43.31	$	94.29	$	47.85	$	96.46
Average Production Cost per Bbl(b)	$	33.91	$	38.81	$	33.34	$	38.87

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

(b) Excludes ad valorem and severance taxes.

General Overview

Operating revenue for the three and nine months ended September 30, 2015 decreased 48.9% and 39.6% when compared to the same periods in 2014, respectively. The decrease in operating revenue for the three and nine months ended September 30, 2015, can be primarily attributed to lower commodity prices and lower production in the Illinois Basin, partially offset by higher production in our Appalachian region. In the Appalachian Basin, our production grew to 16,778 MMcfe for the three-month period ended September 30, 2015, from 14,327 MMcfe for the three-month period ended September 30, 2014, or approximately 17.1%, while production in the Illinois Basin decreased to 183 MBbls during the quarter ended September 30, 2015, from 214 MBbls during the same period in 2014, or approximately 14.5%. The decrease in production in Illinois is primarily related to the natural decline of our conventional oil producing properties. We are currently evaluating strategies to reduce the production declines in the Illinois Basin and will continue to be opportunistic with new well development. For the nine months ended September 30, 2015, production in the Appalachian Basin increased 47.2% to 51,081 MMcfe from the same period in 2014, while production in the Illinois Basin for the nine months ended September 30, 2015 decreased 9.8% to 545 MBbls from the same period in 2014.  For the nine month period ended September 30, 2015, our realized sales price for oil, natural gas, C3+ NGLs and ethane decreased to $43.04 per barrel, $1.99 per Mcf, $15.83 per barrel and $6.82 per barrel, respectively, from $93.29 per barrel, $3.79 per Mcf, $50.74 per barrel and $7.67 per barrel when compared to the same period in 2014.

For the three and nine months ended September 30, 2015, we spent approximately $43.0 million and $173.1 million, respectively, on drilling projects, facilities and related equipment, undeveloped acreage and asset acquisitions. Approximately 92.9% of our capital expenditures in 2015 have been in the Appalachian Basin and approximately 7.1% of our capital expenditures have been in the Illinois Basin.

Operating expenses increased $138.7 million and $300.0 million for the three and nine months ended September 30, 2015, as compared to the same periods in 2014, respectively. Operating expenses primarily comprise: Production and Lease Operating Expenses, G&A Expenses, Other Operating Expense, Exploration Expenses, Impairment Expense and DD&A Expenses. The increases in operating expenses were largely attributable to Production and Lease Operating Expense, Other Operating Expense, DD&A and Impairment Expense. The growth of many 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. The increase in impairment expense is primarily due to conventional oil properties in the Illinois Basin and unconventional gas properties in the Appalachian Basin, where existing market conditions have indicated a significant decrease in the estimated future cash flow of the properties.

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Comparison of the Three Months Ended September 30, 2015 to the Three Months Ended September 30, 2014

Oil, NGL and gas revenue, including the effects of cash settled derivatives, for the three-month periods ended September 30, 2015 and 2014 is summarized in the following table:

	For Three Months Ended September 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2015		2014			Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	10,754	$	27,547		$	(16,793	)		(61.0	)%
Oil derivatives realized(a)	$	2,694	$	(194	)	$	2,888			(1,488.7	)%
Total oil and condensate revenue and derivatives realized	$	13,448	$	27,353		$	(13,905	)		(50.8	)%
Gas sales revenue	$	18,684	$	24,883		$	(6,199	)		(24.9	)%
Gas derivatives realized(a)	$	8,911	$	2,798		$	6,113			218.5	%
Total gas revenue and derivatives realized	$	27,595	$	27,681		$	(86	)		(0.3	)%
C3+ NGL revenue	$	5,069	$	19,136		$	(14,067	)		(73.5	)%
C3+ NGL derivatives realized(a)	$	3,399	$	399		$	3,000			751.9	%
Total C3+ NGL revenue	$	8,468	$	19,535		$	(11,067	)		(56.7	)%
Ethane revenue	$	3,058	$	1,883		$	1,175			62.4	%
Ethane derivatives realized(a)	$	47	$	—		$	47			(—	)%
Total Ethane revenue	$	3,105	$	1,883		$	1,222			64.9	%
Consolidated sales	$	37,565	$	73,449		$	(35,884	)		(48.9	)%
Consolidated derivatives realized(a)	$	15,051	$	3,003		$	12,048			401.2	%
Total oil, NGL and gas revenue and derivatives realized	$	52,616	$	76,452		$	(23,836	)		(31.2	)%
Total Mcfe Production		17,874,302		15,608,493			2,265,809			14.5	%
Average Realized Price per Mcfe	$	2.94	$	4.90		$	(1.96	)		(40.0	)%

(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 2015, after the effect of derivative activities, was $2.94 per Mcfe, a decrease of 40.0%, or $1.96 per Mcfe, from the same period in 2014. This decrease was primarily due to a decrease in commodity prices during the quarter, partially offset by positive cash settlements on derivatives. The average price for natural gas, after the effect of derivative activities, decreased 8.5%, or $0.24 per Mcf, to $2.57 per Mcf. The average price for oil and condensate, after the effect of derivative activities, decreased 44.0%, or $39.33 per barrel, to $50.03 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, decreased 64.2%, or $30.46 per barrel, to $17.00 per barrel. During the second quarter of 2014, we commenced sales of ethane, which had previously been separated from our NGL stream and primarily burned as fuel with small amounts blended with our C3+ NGL sales. The average price for ethane, including the effect of derivatives, during the three months ended September 30, 2015 was approximately $7.33 per barrel as compared to $7.76 per barrel during the same period in 2014. Our derivative activities effectively increased net realized prices by $0.84 per Mcfe in the third quarter of 2015 and $0.19 per Mcfe in the third quarter of 2014.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.99 per mcf during the third quarter of 2015 primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Texas Eastern pipeline, receiving M3 pricing, a New York area index. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have basis swaps in place for 2,300 MMcf at an average differential to Henry Hub NYMEX of $0.82 per Mcf for the remainder of 2015 in addition to basis swaps for 12,510 MMcf at an average differential to Henry Hub NYMEX of $0.90 per Mcf for 2016. During the third quarter of 2015, we received cash settlements of approximately $2.1 million related to our basis swaps. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast.

Production volumes in the third quarter of 2015 increased 14.5% from the third quarter of 2014 primarily due to success of our Marcellus and Utica Shale horizontal drilling activities in the Appalachian Basin, where production increased approximately 17.1%, or 2.5 Bcfe. Natural gas production increased approximately 9.0%, oil and condensate production decreased approximately 12.2%, C3+ NGL production increased approximately 21.0% and our ethane production increased approximately 74.6%. Our production continues to be positively impacted by strong drilling results in the Appalachian Basin.

Overall, our production for the third quarter of 2015 averaged 194,286 Mcfe per day, of which 60.0% was attributable to natural gas, 9.0% to oil and condensate, 16.8% to C3+ NGLs and 14.2% was a result of ethane production.

39

Statements of Operations for the three-month periods ended September 30, 2015 and 2014 are as follows:

	For the Three Months Ended September 30, 2015
($ in Thousands)	2015			2014			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	37,565		$	73,448		$	(35,883	)		(48.9	)%
Other Revenue		8			18			(10	)		(55.6	)%
TOTAL OPERATING REVENUE		37,573			73,466			(35,893	)		(48.9	)%
OPERATING EXPENSES
Production and Lease Operating Expense		30,616			27,674			2,942			10.6	%
General and Administrative Expense		5,376			9,288			(3,912	)		(42.1	)%
(Gain) Loss on Disposal of Asset		(230	)		174			(404	)		(232.2	)%
Impairment Expense		139,810			—			139,810			100.0	%
Exploration Expense		807			1,462			(655	)		(44.8	)%
Depreciation, Depletion, Amortization and Accretion		27,124			26,375			749			2.8	%
Other Operating Expense (Income)		183			(24	)		207			(862.5	)%
TOTAL OPERATING EXPENSES		203,686			64,949			138,737			213.6	%
INCOME (LOSS) FROM OPERATIONS		(166,113	)		8,517			(174,630	)		(2,050.4	)%
OTHER EXPENSE
Interest Expense		(11,886	)		(10,946	)		(940	)		8.6	%
Gain on Derivatives, Net		28,649			12,316			16,333			132.6	%
Other Income		20			3			17			566.7	%
Loss on Equity Method Investments		—			(202	)		202			(100.0	)%
TOTAL OTHER INCOME		16,783			1,171			15,612			1,333.2	%
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(149,330	)		9,688			(159,018	)		(1,641.4	)%
Income Tax (Expense) Benefit		20,037			(4,069	)		24,106			(592.4	)%
INCOME (LOSS) FROM CONTINUING OPERATIONS		(129,293	)		5,619			(134,912	)		(2,401.0	)%
Income From Discontinued Operations, Net of Income Taxes		34,617			970			33,647			3,468.8	%
NET INCOME (LOSS)		(94,676	)		6,589			(101,265	)		(1,536.9	)%
Net Income (Loss) Attributable to Noncontrolling Interests		(1	)		895			(896	)		(100.1	)%
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(94,675	)	$	5,694		$	(100,369	)		(1,762.7	)%

Production and Lease Operating Expense increased approximately $2.9 million, or 10.6%, in the third quarter of 2015 from the same period in 2014. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin and related production as they relate to variable type costs such as transportation, marketing, processing and gathering.Transportation, marketing, processing and gathering fees accounted for approximately 68.1% of our total Production and Lease Operating Expense in the third quarter of 2015 as compared to 56.7% from the same period in 2014. During the third quarter of 2015, approximately $0.7 million of our Production and Lease Operating Expense was related to unutilized transportation, capacity and processing commitments, which is primarily related to unproved properties that we acquired in 2014. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs decreased to $1.71 per Mcfe in the three months ended September 30, 2015 from $1.77 per Mcfe in the same period in 2014.

G&A Expense for the third quarter of 2015 decreased approximately $3.9 million, or 42.1%, to $5.4 million from the same period in 2014. We have undertaken several cost control measures during the first nine months of 2015, including reductions in bonus compensation, reductions in head count, a decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers.

Impairment Expense for the third quarter of 2015 was approximately $139.8 million. We evaluate impairment of our properties when events occur that indicates that the carrying value of these properties may not be recoverable. The expense incurred during the third quarter of 2015 included $118.3 million of proved property impairment and $21.5 million of undeveloped acreage impairment.  The proved property impairment consisted of approximately $77.9 million in our Warrior North project area in the Appalachian Basin and approximately $40.1 million was attributable to our conventional oil properties in the Illinois Basin.  The remaining proved property impairment of approximately $0.3 million is related to our conventional dry gas assets in the Appalachian Basin.  The unproved property impairment consisted of approximately $6.8 million in the Appalachian Basin, primarily attributable to the expected expiration of unconventional natural gas leases, and $14.7 million in the Illinois Basin, primarily attributable to market conditions and lack of future development plans.  The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of September 30, 2015, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline further, downward revisions of proved reserves may be significant and could result in additional impairment expense.

40

Exploration Expense for the third quarter of 2015 was approximately $0.8 million, as compared to $1.5 million for same period in 2014.Approximately $0.2 million of the expense incurred in 2015 was due to geological and geophysical type expenditures and $0.5 million was due to the payment of delay rentals in the Appalachian Basin. The remaining costs are related to dry hole expenses. Approximately $0.9 million of the expense incurred in 2014 was due to geological and geophysical type expenditures. An additional $0.4 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin.  As a result of the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

DD&A Expense for the third quarter of 2015 increased approximately $0.7 million, or 2.8%, from $26.4 million for the same period in 2014. Contributing to the increase in DD&A expense were lower reserves, which were triggered by the ongoing lower commodity pricing environment and the related effect on our estimated proved reserves, and increased production when compared to the same period in 2014.

Interest Expense for the third quarter of 2015 was approximately $11.9 million as compared to $10.9 million for the same period in 2014. The increase in interest expense is primarily due to having an outstanding balance on our Senior Credit Facility for the quarter compared to the payoff of the outstanding balance in July 2014. We discuss our Senior Notes and Senior Credit Facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain on Derivatives, net included a gain of approximately $28.6 million for the third quarter of 2015 as compared to a gain of $12.3 million for the same period in 2014. The gain recorded for the third quarter of 2015 included cash receipts for commodity and interest rate derivatives of $15.1 million while the gain incurred in the third quarter of 2014 included cash receipts of approximately $3.0 million for commodity and interest rate derivatives. 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 gas production volumes given the highly volatile oil, NGL and gas commodities market.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2015 and 2016, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Income Tax (Expense) Benefit was a benefit of approximately $20.0 million for the third quarter of 2015, as compared to a $4.1 million of expense for the same period in 2014. Our effective tax rate during the three months ended September 30, 2015, was approximately 13.4%, as compared to 42.0% during the comparable period in 2014. Our effective tax rate in the third quarter of 2015 was different than the statutory rate of 35% due to the recording of a valuation allowance. As of September 30, 2015, we had a significant level of future tax benefits, some of which are not expected to be fully utilized, therefore limiting our ability to recognize further tax benefits.

41

Net Income (Loss) Attributable to Rex Energy for the third quarter of 2015 was approximately $94.7 million of loss, as compared $5.7 million of income for the comparable period in 2014 as a result of the factors discussed above.

Comparison of the Nine Months Ended September 30, 2015 to the Nine Months Ended September 30, 2014

Oil, NGL and gas revenue, including the effects of cash settled derivatives, for the nine -month periods ended September 30, 2015 and 2014 is summarized in the following table:

	For Nine Months Ended September 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2015		2014			Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	38,350	$	75,407		$	(37,057	)		(49.1	)%
Oil derivatives realized(a)	$	8,806	$	(1,622	)	$	10,428			(642.9	)%
Total oil and condensate revenue and derivatives realized	$	47,156	$	73,785		$	(26,629	)		(36.1	)%
Gas sales revenue	$	68,057	$	97,381		$	(29,324	)		(30.1	)%
Gas derivatives realized(a)	$	23,250	$	(1,544	)	$	24,794			(1,605.8	)%
Total gas revenue and derivatives realized	$	91,307	$	95,837		$	(4,530	)		(4.7	)%
C3+ NGL revenue	$	24,872	$	52,895		$	(28,023	)		(53.0	)%
C3+ NGL derivatives realized(a)	$	6,939	$	(1,044	)	$	7,983			(764.7	)%
Total C3+ NGL revenue	$	31,811	$	51,851		$	(20,040	)		(38.6	)%
Ethane revenue	$	6,158	$	1,967		$	4,191			213.1	%
Ethane derivatives realized(a)	$	172	$	—		$	172			(—	)%
Total Ethane revenue	$	6,330	$	1,967		$	4,363			221.8	%
Consolidated sales	$	137,437	$	227,650		$	(90,213	)		(39.6	)%
Consolidated derivatives realized(a)	$	39,167	$	(4,210	)	$	43,377			(1,030.3	)%
Total oil, NGL and gas revenue and derivatives realized	$	176,604	$	223,440		$	(46,836	)		(21.0	)%
Total Mcfe Production		54,353,317		38,325,127			16,028,190			41.8	%
Average Realized Price per Mcfe	$	3.25	$	5.83		$	(2.58	)		(44.3	)%

(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 2015, after the effect of derivative activities, was $3.25 per Mcfe, a decrease of 44.3%, or $2.58 per Mcfe, from the same period in 2014. This decrease was primarily due to a decrease in commodity prices during the period, partially offset by positive cash settlements on derivatives. The average price for natural gas, after the effect of derivative activities, decreased 28.4%, or $1.06 per Mcf, to $2.67 per Mcf. The average price for oil and condensate, after the effect of derivative activities, decreased 42.0%, or $38.36 per barrel, to $52.92 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, decreased 59.3%, or $29.50 per barrel, to $20.24 per barrel. During the second quarter of 2014, we commenced sales of ethane, which had previously been separated from our NGL stream and primarily burned as fuel with small amounts blended with our C3+ NGL sales. The average price for ethane, including the effect of derivatives, during the nine months ended September 30, 2015 was approximately $7.01 per barrel as compared to $7.67 per barrel for the same period in 2014. Our derivative activities effectively increased net realized prices by $0.72 per Mcfe in the first nine months of 2015 and effectively decreased net realized prices by $0.11 per Mcfe in the first nine months of 2014.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.77 per Mcf during the first nine months of 2015 primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Texas Eastern pipeline, receiving M3 pricing, a New York area index. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have basis swaps in place for 2,300 MMcf at an average differential to Henry Hub NYMEX of $0.82 per Mcf for the remainder of 2015 in addition to basis swaps for 12,510 MMcf at an average differential to Henry Hub NYMEX of $0.90 per Mcf for 2016. During the first nine months of 2015, we received cash settlements of approximately $3.8 million related to our basis swaps. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast.

Production volumes in the first nine months of 2015 increased 41.8% from the first nine months of 2014 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities in the Appalachian Basin, where production increased approximately 47.2%, or 16.4 Bcfe. Natural gas production increased approximately 33.0%, oil and condensate production increased approximately 10.2%, NGL production increased approximately 50.7% and our ethane production increased by 252.1%. Our production continues to be positively impacted by strong drilling results in the Appalachian Basin. During June 2014, we commenced incremental ethane recovery, which had previously been blended with our natural gas sales.

Overall, our production for the first nine months of 2015 averaged 199,096 Mcfe per day, of which 62.7% was attributable to natural gas, 9.8% to oil and condensate, 17.3% to C3+ NGLs and 10.0% was a result of ethane production.

42

Statements of Operations for the nine-month periods ended September 30, 2015 and 2014 are as follows:

	For the Nine Months Ended September 30,
($ in Thousands)	2015			2014			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	137,437		$	227,650		$	(90,213	)		(39.6	)%
Other Revenue		30			92			(62	)		(67.4	)%
TOTAL OPERATING REVENUE		137,467			227,742			(90,275	)		(39.6	)%
OPERATING EXPENSES
Production and Lease Operating Expense		90,310			69,338			20,972			30.2	%
General and Administrative Expense		23,507			27,179			(3,672	)		(13.5	)%
(Gain) Loss on Disposal of Asset		(465	)		468			(933	)		(199.4	)%
Impairment Expense		264,677			41			264,636		N/M
Exploration Expense		2,242			4,890			(2,648	)		(54.2	)%
Depreciation, Depletion, Amortization and Accretion		82,788			66,454			16,334			24.6	%
Other Operating Expense		5,304			3			5,301		N/M
TOTAL OPERATING EXPENSES		468,363			168,373			299,990			178.2	%
INCOME (LOSS) FROM OPERATIONS		(330,896	)		59,369			(390,265	)		(657.4	)%
OTHER EXPENSE
Interest Expense		(36,097	)		(25,236	)		(10,861	)		43.0	%
Gain on Derivatives, Net		45,487			2,315			43,172			1,864.9	%
Other Income		119			20			99			495.0	%
Loss on Equity Method Investments		(411	)		(610	)		199			(32.6	)%
TOTAL OTHER INCOME (EXPENSE)		9,098			(23,511	)		32,609			(138.7	)%
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(321,798	)		35,858			(357,656	)		(997.4	)%
Income Tax (Expense) Benefit		20,653			(13,839	)		34,492			(249.2	)%
INCOME (LOSS) FROM CONTINUING OPERATIONS		(301,145	)		22,019			(323,164	)		(1,467.7	)%
Income From Discontinued Operations, Net of Income Taxes		38,149			3,963			34,186			862.6	%
NET INCOME (LOSS)		(262,996	)		25,982			(288,978	)		(1,112.2	)%
Net Income Attributable to Noncontrolling Interests		2,245			3,340			(1,095	)		(32.8	)%
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(265,241	)	$	22,642		$	(287,883	)		(1,271.5	)%

Production and Lease Operating Expense increased approximately $21.0 million, or 30.2%, in the first nine months of 2015 from the same period in 2014. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. For the nine months ended September 30, 2015, transportation, marketing, processing and gathering fees accounted for approximately 66.7% of our total Production and Lease Operating Expense as compared to 52.1% in the first nine months of 2014. During the first nine months of 2015, approximately $2.8 million of our Production and Lease Operating Expense was related to unutilized transportation, capacity and processing commitments, of which the majority is related to unproved properties that we acquired in 2014. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs decreased to $1.66 per Mcfe in the nine months ended September 30, 2015 from $1.81 per Mcfe in the same period in 2014.

G&A Expense for the nine months ended September 30, 2015 decreased approximately $3.7 million, or 13.5%, to $23.5 million from the same period in 2014. The decrease in expense was due to several cost control measures taken during the first nine months of 2015, including reductions in bonus compensation, reductions in head count, a decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers.

Impairment Expense for the nine months ended September 30, 2015 was approximately $264.7 million. We evaluate impairment of our properties when events occur that indicates that the carrying value of these properties may not be recoverable. The expense incurred during the first nine months of 2015 included proved property impairments of approximately $211.4 million, with approximately $170.5 million attributable to unconventional assets in the Appalachian Basin and $40.0 million attributable to our conventional oil properties in the Illinois Basin.  The remaining proved property impairment expense is related to our conventional dry gas assets in the Appalachian Basin.  Unproved property impairments for the nine months ended September 30, 2015, consisted of approximately $38.5 million related to our unconventional assets in the Appalachian Basin and $14.8 million related to our conventional oil properties in the Illinois Basin.  The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of September 30, 2015, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline further, downward revisions of proved reserves may be significant and could result in additional impairment expense.

43

Exploration Expense for the nine months ended September 30, 2015 was approximately $2.2 million, as compared to $4.9 million for same period in 2014. Approximately $0.8 million of the expense incurred in 2015 was due to geological and geophysical type expenditures and $1.0 million was due to delay rentals in the Appalachian Basin. An additional $0.3 million was due to dry hole expense for Illinois non-operated properties located in the Illinois Basin.  Approximately $3.3 million of the expense incurred in 2014 was due to geological and geophysical type expenditures. An additional $1.2 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin. In conjunction with the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

DD&A Expense for the nine months ended September 30, 2015 increased approximately $16.3 million, or 24.6%, from $66.5 million for the same period in 2014. Contributing to the increase in DD&A expense were lower reserves, which were triggered by the ongoing lower commodity pricing environment, and increased production when compared to the same period in 2014.

Other Operating Expense for the nine months ended September 30, 2015 increased approximately $5.3 million from a negligible amount for the same period in 2014. The period-over-period increase in Other Operating Expense is due to fees incurred associated with the early termination of two drilling rig contacts during the first quarter of 2015 in response to depressed commodity prices. Both drilling rigs were operated within our Appalachian Basin region. We currently have one drilling rig that remains active in the area.

Interest Expense for the nine months ended September 30, 2015 was approximately $36.1 million as compared to $25.2 million for the same period in 2014. The increase in interest expense is primarily due to the issuance of $325.0 million in Senior Notes due 2022 in July 2014 as well as the outstanding balance on our Senior Credit Facility for a portion of the quarter. We discuss our Senior Notes and senior credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain on Derivatives, net included a gain of approximately $45.5 million for the first nine months of 2015 as compared to a gain of $2.3 million for the same period in 2014. The gain recorded for the first nine months of 2015 included cash receipts for commodity and interest rate derivatives of $40.1 million while the gain incurred in the first nine months of 2014 included cash payments of approximately $3.3 million related to commodity and interest rate derivatives. 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 gas production volumes given the highly volatile oil, NGL and gas commodities market.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2015 and 2016, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Income Tax (Expense) Benefit was approximately $20.7 million of benefit for the nine months ended September 30, 2015, as compared to $13.8 million of expense for the same period in 2014. Our effective tax rate during the nine months ended September 30, 2015, was approximately 6.4%, as compared to 38.6% during the comparable period in 2014. Our effective tax rate in the third quarter of 2015 was different than the statutory rate of 35% due to the recording of a valuation allowance. As of September 30, 2015, we had a significant level of future tax benefits, some of which are not expected to be fully utilized, therefore limiting our ability to recognize further tax benefits.

Net Income (Loss) Attributable to Rex Energy for the first nine months of 2015 was approximately $265.2 million of loss, as compared $22.6 million of income for the comparable period in 2014 as a result of the factors discussed above.

	Other Performance Measurements
	For Three Months Ended September 30,				For Nine Months Ended September 30,
	2015		2014		2015		2014
EBITDAX from Continuing Operations ($ in Thousands) (a)	$	16,417	$	41,053	$	68,170	$	132,149
LOE per Mcfe	$	1.71	$	1.77	$	1.66	$	1.81
G&A per Mcfe	$	0.30	$	0.60	$	0.43	$	0.71

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

EBITDAX (Non-GAAP)

EBITDAX (Non-GAAP) from continuing operations decreased approximately $24.6 million to $16.4 million for the three-month period ended September 30, 2015, as compared to the same period in 2014. EBITDAX from continuing operations decreased

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approximately $64.0 million to $68.2 million for the nine -month period ended September 30, 2015, as compared to the same period in 2014.  The decrease in EBITDAX can be primarily attributed to decreased average sales prices for oil, natural gas and NGLs, resulting in decreased operating revenues as well as increases in lease operating expenses. These decreases to EBITDAX were partially offset by increases in production. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

LOE per Mcfe

LOE per Mcfe measures the average cost of extracting oil, NGLs and natural gas from our basin reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our oil, NGL and natural gas reserves in the ground. LOE per Mcfe decreased to $1.71 for the three months ended September 30, 2015 as compared to $1.77 for the same period in 2014. LOE per Mcfe decreased to $1.66 for the nine months ended September 30, 2015 as compared to $1.81 for the same period in 2014. Our LOE is largely comprised of variable type costs such as transportation, marketing, processing and gathering. For the first nine months of 2015, transportation, capacity and processing fees accounted for approximately 66.7% of our total Production and Lease Operating Expense as compared to 52.1% during the same period of 2014. 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. The decrease in our LOE per Mcfe when comparing the three and nine months ended September 30, 2015 to the comparable periods in 2014, is primarily due to our increased production in the Appalachian Basin combined with our relatively consistent levels of fixed expenses. 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 $0.30 for the three-month period ended September 30, 2015, as compared to $0.60 for the same period in 2014. G&A expenses per Mcfe decreased to approximately $0.43 for the nine-month period ended September 30, 2015, as compared to $0.71 for the same period in 2014. The year-over-year decrease is predominately due to cost control measures implemented during first quarter 2015 in response to our decreased capital plan related to commodity price declines combined with our increase in production.

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, 2015, we spent $173.1 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage, net of the proceeds we received from the closing of the ArcLight joint venture. We funded our capital program with the proceeds from an offering of Senior Notes due 2022 and preferred stock, net cash flows from operations, proceeds from our Senior Credit Facility and with funds we received from the closing of the ArcLight joint venture. The remainder of our 2015 capital budget is expected to be funded primarily by cash on hand, cash flow from operations, potential future asset sales and joint ventures, and borrowings under our Senior Credit Facility, of which approximately $270.3 million was available at September 30, 2015. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, further significant decreases in commodity prices, particularly natural gas, or reductions 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 or sell non-core assets 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 natural gas reserves. If commodity prices decrease further, our operating cash flows may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of commodity prices on cash flows can be mitigated through the use of commodity derivatives. If we are unable to replace our oil, NGL and natural gas reserves through our acquisitions, development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under the Senior Credit Facility. Under extreme circumstances, commodity price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

Our cash flows from operations are driven by commodity prices and production volumes. Prices for oil, NGLs and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from national and global supply and demand for hydrocarbons. Our working capital is significantly influenced by

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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, 2015, we had approximately $69.0 million in borrowings outstanding under our Senior Credit Facility and had approximately $270.3 million available to us with approximately $3.2 million of cash on hand. As of September 30, 2015, we were in compliance with all required debt covenants under our revolving credit facility.

The Senior Notes are unsecured, and are governed by indentures with substantially similar terms and provisions (the “Indentures”).  The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25:1.  As of September 30, 2015, our Fixed Charge Coverage Ratio was 1.73.  We expect our Fixed Charge Coverage Ratio to be less than 2.25:1 for the rest of 2015 and 2016. As a result, we anticipate that our ability to incur debt, pay dividends or make certain other restricted payments will be subject to the more restrictive provisions of the Indentures for those periods. The Indentures also contain customary events of default. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.  Management does not believe that any acceleration of payment will occur within the next twelve months.

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. As market conditions warrant and subject to our contractual restrictions in our Senior Credit Facility or otherwise, our liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, restructuring of existing debt, repurchases of shares of our common stock or outstanding debt, including our senior notes, by tender offer or otherwise, and other similar transactions. The amounts involved in any of these transactions, individually or in the aggregate, may be material.

Future Liquidity Considerations

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay minimum fees in connection with these agreements of $151.7 million over the next five years, depending on our levels of production. Also in connection with certain of these agreements, weconcurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $425.7 millionover the life of the agreements.

In connection with our Senior Notes due 2020 and our Senior Notes due 2022, we have interest payments due each year of approximately $31.1 million and $20.3 million, respectively. We are also required to make quarterly dividend payments related to our Series A Preferred Stock which total approximately $9.7 million annually.

Financial Condition and Cash Flows for the Nine Months Ended September 30, 2015 and 2014

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

	Nine Months Ended September 30,
($ in Thousands)	2015			2014
Cash flows provided by operations	$	13,419		$	133,563
Cash flows used in investing activities		(96,802	)		(463,359	)
Cash flows provided by financing activities		68,437			415,518
Net increase (decrease) in cash and cash equivalents	$	(14,946	)	$	85,722

Net cash provided by operating activities decreased by approximately $120.1 million in the first nine months of 2015, to $13.4 million, over the same period in 2014. This was primarily due to a reduction in oil, natural gas and NGL prices, increased lease operating expenses and payments related to our early termination of two drilling rig contracts. These decreases in cash flow were partially offset by increases in production in our Appalachian Basin operations. Our cash flows were negatively impacted by lower commodity prices, net of our increases in production, by approximately $90.2 million, which was partially offset by an increase in cash settlements on derivatives of approximately $43.4 million.

Net cash used in investing activities decreased by approximately $366.6 million from the first nine months of 2015 to $96.8 million over the same period in 2014. This change is primarily attributed to lower activity levels related to the currently depressed

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commodity price environment, the $66.1 million in proceeds received from the sale of Water Solutions and from our joint venture with ArcLight.

Net cash provided by financing activities decreased by approximately $347.0 million for the first nine months of 2015 to $68.4 million from $415.5 million over the same period in 2014. During the first nine months of 2015, we had net borrowings of approximately $76.5 million compared to net borrowings of $261.2 million for the first nine months of 2014. Our decrease in net borrowings is primarily due to cash received of approximately $325.0 million from the 2022 Senior Notes offering in third quarter of 2014. Also contributing to the decrease in cash provided by financing activities were the net proceeds from the issuance of preferred stock of $155.0 million in 2014.

As market conditions warrant and subject to our contractual restrictions in the Credit Facility or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, repurchases of shares of our common stock or outstanding debt, including our senior unsecured notes, by tender offer or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

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, 2015, 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, 2014. We describe critical recently adopted and issued accounting standards in Part I, 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, unrealized losses from financial derivatives, 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.

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

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

The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in Thousands)	2015			2014			2015			2014
Net Income (Loss) From Continuing Operations	$	(129,293	)	$	5,619		$	(301,145	)	$	22,019
Add Back Non-Recurring Costs1		—			—			4,774			—
Add Back Depletion, Depreciation, Amortization and Accretion		27,124			26,375			82,788			66,454
Add Back (Less) Non-Cash Compensation Expense (Income)		(83	)		1,521			4,834			4,245
Add Back Interest Expense		11,886			10,946			36,097			25,236
Add Back Impairment Expense		139,810			—			264,677			41
Add Back Exploration Expenses		807			1,462			2,242			4,890
Add Back (Less) Loss (Gain) on Disposal of Assets		(230	)		174			(465	)		468
Less Gain on Financial Derivatives		(28,649	)		(12,316	)		(45,487	)		(2,315	)
Add Back (Less) Cash Settlement of Derivatives		15,082			3,002			40,102			(3,331	)
Add Back (Less) Income Tax Expense (Benefit)		(20,037	)		4,069			(20,653	)		13,839
Add Back Non-Cash Portion of Equity Method Investments		—			201			406			603
EBITDAX From Continuing Operations	$	16,417		$	41,053		$	68,170		$	132,149
Net Income From Discontinued Operations	$	34,617		$	970		$	38,149		$	3,963
(Income) Loss Attributable to Noncontrolling Interests		1			(895	)		(2,245	)		(3,340	)
Income From Discontinued Operations Attributable to Rex Energy		34,618			75			35,904			623
Add Back Depletion, Depreciation, Amortization and Accretion		2			989			78			2,560
Add Back Interest Expense		56			134			487			482
Less Gain on Disposal of Assets2		(57,013	)		(91	)		(57,055	)		(84	)
Less Non-Cash Portion of Noncontrolling Interests		(23	)		(410	)		(209	)		(1,184	)
Add Back Income Tax Expense		22,452			400			23,310			754
Add EBITDAX From Discontinued Operations	$	92		$	1,097		$	2,515		$	3,151
EBITDAX (Non-GAAP)	$	16,509		$	42,150		$	70,685		$	135,300

¹ Non-Recurring costs for the nine months ended September 30, 2015 are due to net fees incurred to terminate two drilling rig contracts earlier than their original term.

² Gain on disposal included in EBITDAX from Discontinued Operations for the three and nine months ended September 30, 2015, includes approximately $57.0 million in gains recognized on the sale of Water Solutions.

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, 2015, we received net settlements, excluding basis differential derivatives, on oil, NGL and natural gas derivatives of approximately $12.9 million and $35.3 million, respectively, as compared to receiving net settlements of approximately $3.0 million for the three months ended September 30, 2014 and paying net settlements of $4.2 million for the nine months ended September 30, 2014. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of September 30, 2015, we had over 75.0% and 18.0% of our annualized oil production hedged through the remainder of 2015 and 2016, respectively, over 85.0% and 77.0% of our annualized natural gas production hedged through the remainder of 2015 and 2016, respectively, and over 59.0% and 41.0% of our annualized NGL production hedged through the remainder of 2015 and 2016, respectively. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion activity or the natural decline of our oil and gas production.

Our primary sources of production and revenue are located in the Appalachian Basin. Natural gas prices in the Appalachian Basin are exposed to regional differentials when compared to NYMEX pricing. During the three and nine months ended September 30, 2015, our average realized prices for natural gas was lower than the average NYMEX prices over the same period by

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approximately $0.99 per Mcf and $0.77 per Mcf, respectively. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have basis swaps in place for 2,300 MMcf at an average differential to Henry Hub NYMEX of $0.82 per Mcf for the remainder of 2015 in addition to basis swaps for 12,510 MMcf at an average differential to Henry Hub NYMEX of $0.90 per Mcf for 2016. For the three and nine months ended September 30, 2015, we received cash settlements on our basis differential derivatives of approximately $2.2 million and $3.8 million, respectively.

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 five 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, 2015, refer to Part I, Item 1. Financial Statements—Note 8, “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, operational commitments, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2014, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our borrowings under the Senior Credit Facility. See Part I, Item 1. Financial Statements—Note 7, “Long-Term Debt” for additional information on the Senior Credit Facility.

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.

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, 2015, 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 2015 average would reduce our gross revenues, before the effects of derivatives, for the remaining three months of 2015 by approximately $4.6 million.

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

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At September 30, 2015, we had the following commodity derivative contracts outstanding:

Period	Volume	Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2015 - Collars	75,000 Bbls	$	—	$	52.90	$	63.15	$	—		$	556
2015 - Three-Way Collars	150,000 Bbls		50.00		65.00		72.50		—			2,102
2016 - Collars	60,000 Bbls		—		53.75		63.81		—			467
2016 - Three-Way Collars	45,000 Bbls		50.00		65.00		70.00		—			423
2016 - Deferred Put Spreads	120,000 Bbls		50.00		65.00		—		—			531
	450,000 Bbls										$	4,079
Natural Gas
2015 - Swaps	4,375,000 Mcf	$	—	$	—	$	—	$	3.49		$	3,891
2015 - Swaptions	550,000 Mcf		—		—		—		3.53			453
2015 - Cap Swaps	1,950,000 Mcf		3.43		—		—		4.12			1,170
2015 - Three-Way Collars	2,200,000 Mcf		2.84		3.53		4.25		—			881
2015 - Put Spreads	650,000 Mcf		2.56		3.32		—		—			336
2015 - Calls	750,000 Mcf		—		—		4.15		—			—
2015 - Basis Swaps - Dominion South	2,300,000 Mcf		—		—		—		(0.82	)		101
2016 - Swaps	9,600,000 Mcf		—		—		—		3.45			6,207
2016 - Swaptions	0 Mcf		—		—		—		—			(305	)
2016 - Cap Swaps	3,600,000 Mcf		3.45		—		—		4.11			1,848
2016 - Collars	900,000 Mcf		—		3.20		4.04		—			427
2016 - Three-Way Collars	19,170,000 Mcf		2.51		3.22		3.99		—			4,620
2016 - Put Spreads	2,100,000 Mcf		2.25		3.00		—		—			172
2016 - Basis Swaps - Dominion South	12,510,000 Mcf		—		—		—		(0.90	)		(124	)
2017 - Swaps	960,000 Mcf		—		—		—		3.60			614
2017 - Cap Swaps	2,100,000 Mcf		3.34		—		—		4.07			1,122
2017 - Three-Way Collars	13,900,000 Mcf		2.38		3.09		4.02		—			2,670
2017 - Calls	840,000 Mcf		—		—		4.00		—			(93	)
2017 - Basis Swaps - Dominion South	4,550,000 Mcf		—		—		—		(0.83	)		(353	)
2017 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(15	)
2018 - Swaps	960,000 Mcf		—		—		—		3.60			614
2018 - Cap Swaps	1,800,000 Mcf		3.30		—		—		4.05			975
2018 - Three-Way Collars	5,475,000 Mcf		2.40		3.00		3.75		—			296
2018 - Calls	3,650,000 Mcf		—		—		4.25		—			(439	)
2018 - Basis Swaps - Dominion South	6,400,000 Mcf		—		—		—		(0.83	)		(515	)
2018 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(15	)
2019 - Basis Swaps - Dominion South	7,300,000 Mcf		—		—		—		(0.83	)		(592	)
2020 - Basis Swaps - Dominion South	7,320,000 Mcf		—		—		—		(0.83	)		(596	)
	145,110,000 Mcf										$	23,350
NGLs
2015 - C3+ NGL Swaps	387,000 Bbls	$	—	$	—	$	—	$	31.92		$	2,642
2015 - Ethane Swaps	102,600 Bbls		—		—		—		8.40			5
2016 - C3+ NGL Swaps	1,131,000 Bbls		—		—		—		32.76			6,848
2016 - Ethane Swaps	240,000 Bbls		—		—		—		8.82			54
2017 - C3+ NGL Swaps	132,000 Bbls		—		—		—		19.74			(38	)
	1,992,600 Bbls										$	9,511
Refined Product (Heating Oil)
2016 - Swaps	12,000 Bbls	$	—	$	—	$	—	$	84.00		$	(185	)
	12,000 Bbls										$	(185	)

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. As of September 30, 2015, we did not have any interest rate derivatives in place, however we do from time to time enter interest rate derivatives to manage our interest rate exposure. We did not have any interest rate derivatives in place as of December 31, 2014. During the nine months ended September 30, 2015, we received cash payments of approximately $0.9 million related to our historical interest rate swaps. Based on our variable rate debt as of September 30, 2015 of approximately $69.0 million, a 1.0% change in interest rates would impact our interest expense by approximately $0.7 million.

Item 4. Controls And Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed,

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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, 2015, 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, 2015 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 subsections Legal Reserves and Environmental in Note 12, Commitments and Contingencies, to our Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

Item1A. Risk Factors.

During the quarter ended September 30, 2015, 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, 2014, except for the following:

The value of our proved reserves as of December 31, 2014 calculated using SEC pricing may be higher than the fair market value of our proved reserves calculated using current market prices.

Our estimated proved reserves as of December 31, 2014 and related PV-10 and Standardized Measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $94.99 per barrel of oil (WTI) and $4.35 per MMBtu (Henry Hub spot). Through September 30, 2015, the twelve-month trailing average price for crude oil was $55.73 per Bbl and the twelve-month trailing average price of natural gas was $3.06 per MMBtu. Using more recent prices in estimating our proved reserves, without giving effect to any acquisitions or development activities we have executed during 2015, would likely result in a reduction in proved reserve volumes due to economic limits.  Furthermore, any such reduction in proved reserve volumes combined with lower commodity prices would substantially reduce the PV-10 and Standardized Measure of our proved reserves as of a more recent date.

Although we have hedged a portion of our estimated 2015 production, our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of oil and natural gas.

As of September 30, 2015, we had over 75.0% and 18.0% of our annualized oil production hedged through the remainder of 2015 and 2016, respectively, over 85.0% and 77.0% of our annualized natural gas production hedged through the remainder of 2015 and 2016, respectively, and over 59.0% and 41.0% of our annualized NGL production hedged through the remainder of 2015 and 2016, respectively. In addition, we have basis swaps in place for 2,300 MMcf at an average differential to Henry Hub NYMEX of $0.82 per Mcf for the remainder of 2015 and basis swaps for 12,510 MMcf at an average differential to Henry Hub NYMEX of $0.90 per Mcf for 2016. These hedges may be inadequate to protect us from continuing and prolonged decline in the price of oil and natural gas. To the extent that the price of oil and natural gas remain at current levels or declines further, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.

The prevailing commodity price environment may require us to sell certain assets, restructure our debt or capital structure, or raise additional capital to fund our operations.

If low commodity prices continue, we may need to restructure our debt, issue equity, or engage in asset sales or other capital raising transactions to fund our operations, meet our debt service obligations of approximately $51.4 million per year, and pay our Series A Preferred Stock dividends of approximately $9.7 million per year.  Our management is actively pursuing improving our working capital position and reducing our future debt service obligations.

Item 6.Exhibits.

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

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SIGNATURES

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

	REX ENERGY CORPORATION (Registrant)
Date: November 9, 2015	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)

Date: November 9, 2015	By:	/s/ Thomas Rajan
		Thomas Rajan
		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	Certificate of Designations, Preferences, Rights and Limitations of 6.00% Convertible Perpetual Preferred Stock, Series A, 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 August 18, 2014).
3.4	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).
3.5	Amendment to the Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K as filed with the SEC on August 18, 2014).
4.1	Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
4.2	Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
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).
4.7	Indenture dated as of July 17, 2014 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 July 17, 2014).
4.8	Form of 6.250% Senior Notes due 2022 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on July 17, 2014, and incorporated herein by reference).
4.9	Registration Rights Agreement dated as of July 17, 2014 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 SEC on July 17, 2014).
4.10	Deposit Agreement, dated August 18, 2014, by and among the Company, Computershare Trust Company, N.A. and Computershare Inc., together as depositary, and holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).
4.11	Form of Depositary Receipt Representing the Depositary Shares (included as Exhibit A to Exhibit 4.10) (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).
10.1*	Eighth Amendment to Amended and Restated Credit Agreement effective as of September 4, 2015, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto.
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.

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Exhibit Number	Exhibit Title
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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