rexx-10q_20160630.htm

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:

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

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:

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.

	June 30, 2016 (unaudited)			December 31, 2015
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,438		$	1,091
Accounts Receivable		31,644			17,274
Taxes Receivable		48			18
Short-Term Derivative Instruments		4,760			34,260
Inventory, Prepaid Expenses and Other		1,688			3,059
Assets Held for Sale		46,549			60,451
Total Current Assets		88,127			116,153
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,020,936			943,092
Unevaluated Oil and Gas Properties		232,674			262,992
Other Property and Equipment		21,444			20,363
Wells and Facilities in Progress		75,992			141,100
Pipelines		14,144			14,024
Total Property and Equipment		1,365,190			1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(459,427	)		(437,828	)
Net Property and Equipment		905,763			943,743
Other Assets		2,490			2,501
Long-Term Derivative Instruments		1,526			9,534
Total Assets	$	997,906		$	1,071,931
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	51,915		$	36,785
Current Maturities of Long-Term Debt		172			402
Accrued Liabilities		30,346			40,608
Short-Term Derivative Instruments		15,902			2,486
Liabilities Related to Assets Held for Sale		39,935			36,320
Total Current Liabilities		138,270			116,601
Long-Term Derivative Instruments		10,091			5,556
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		141,237			109,386
Senior Notes, Net of Issuance Costs		637,314			663,089
Premium on Senior Notes, Net		1,524			2,344
Other Deposits and Liabilities		2,860			3,156
Future Abandonment Cost		7,731			11,568
Total Liabilities	$	939,027		$	911,700
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 4,087 issued and outstanding on June 30, 2016 and 16,100 shares issued and outstanding on December 31, 2015	$	1		$	1
Common Stock, $.001 par value per share, 200,000,000 shares authorized and 78,440,589 shares issued and outstanding on June 30, 2016 and 55,741,229 shares issued and outstanding on December 31, 2015		77			54
Additional Paid-In Capital		637,223			623,863
Accumulated Deficit		(578,422	)		(463,687	)
Total Stockholders’ Equity		58,879			160,231
Total Liabilities and Stockholders’ Equity	$	997,906		$	1,071,931

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	31,271		$	35,772		$	56,944		$	81,696
Other Revenue (Expense)		(6	)		12			7			22
TOTAL OPERATING REVENUE		31,265			35,784			56,951			81,718
OPERATING EXPENSES
Production and Lease Operating Expense		25,221			24,270			49,672			47,387
General and Administrative Expense		4,837			7,394			10,121			15,745
Gain on Disposal of Assets		(4,307	)		(373	)		(4,295	)		(309	)
Impairment Expense		25,139			117,839			35,780			124,687
Exploration Expense		803			755			1,738			1,194
Depreciation, Depletion, Amortization and Accretion		14,750			24,698			31,262			46,537
Other Operating (Income) Expense		704			(66	)		1,030			5,138
TOTAL OPERATING EXPENSES		67,147			174,517			125,308			240,379
LOSS FROM OPERATIONS		(35,882	)		(138,733	)		(68,357	)		(158,661	)
OTHER INCOME (EXPENSE)
Interest Expense		(11,439	)		(12,181	)		(24,469	)		(24,193	)
Gain (Loss) on Derivatives, Net		(29,169	)		(281	)		(25,120	)		16,838
Other Income		12			61			12			92
Debt Exchange Expense		(533	)		—			(9,014	)		—
Gain on Extinguishment of Debt		23,707			—			23,707			—
Loss on Equity Method Investments		—			(208	)		—			(411	)
TOTAL OTHER INCOME (EXPENSE)		(17,422	)		(12,609	)		(34,884	)		(7,674	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(53,304	)		(151,342	)		(103,241	)		(166,335	)
Income Tax (Expense) Benefit		393			—			(2,321	)		—
NET LOSS FROM CONTINUING OPERATIONS		(52,911	)		(151,342	)		(105,562	)		(166,335	)
Loss From Discontinued Operations, Net of Income Taxes		(1,683	)		(461	)		(9,173	)		(1,985	)
NET LOSS		(54,594	)		(151,803	)		(114,735	)		(168,320	)
Net Income Attributable to Noncontrolling Interests		—			949			—			2,246
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(54,594	)	$	(152,752	)	$	(114,735	)	$	(170,566	)
Preferred Stock Dividends		(1,723	)		(2,415	)		(3,828	)		(4,830	)
Effect of Preferred Stock Conversions		72,316			—			72,316			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	15,999		$	(155,167	)	$	(46,247	)	$	(175,396	)
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	0.24		$	(2.84	)	$	(0.58	)	$	(3.16	)
Basic – Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders		(0.02	)		(0.03	)		(0.14	)		(0.08	)
Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.22		$	(2.87	)	$	(0.72	)	$	(3.24	)
Basic – Weighted Average Shares of Common Stock Outstanding		71,804			54,118			64,044			54,090
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	0.24		$	(2.84	)	$	(0.58	)	$	(3.16	)
Diluted – Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders		(0.02	)		(0.03	)		(0.14	)		(0.08	)
Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.22		$	(2.87	)	$	(0.72	)	$	(3.24	)
Diluted – Weighted Average Shares of Common Stock Outstanding		71,804			54,118			64,044			54,090

	Common Stock				Preferred Stock
	Shares		Par Value		Shares			Par Value		Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Equity
BALANCE December 31, 2015		55,741	$	54		16		$	1	$	623,863		$	(463,687	)	$	160,231
Non-Cash Compensation		—		—		—			—		1,275			—			1,275
Issuance of Common Stock in Debt Exchange		8,413		9		—			—		6,404			—			6,413
Issuance of Common Stock for Debt Extinguishments		5,227		5							5,690						5,695
Issuance of Restricted Stock, Net of Forfeitures		48		—		—			—		—			—			—
Conversion of Preferred Stock to Common Stock		9,012		9		(12	)		—		(9	)		—			—
Net Loss		—		—		—			—		—			(114,735	)		(114,735	)
BALANCE June 30, 2016		78,441	$	77		4		$	1	$	637,223		$	(578,422	)	$	58,879

	For the Six Months Ended June 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(114,735	)	$	(168,320	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		—			411
Non-cash Expenses		10,100			5,884
Depreciation, Depletion, Amortization and Accretion		36,345			55,740
Gain on Derivatives		25,120			(16,838	)
Cash Settlements of Derivatives		30,340			25,020
Dry Hole Expense		870			289
Impairment Expense		39,323			124,867
Gain on Extinguishment of Debt		(23,757	)		—
Gain on Sale of Assets		(4,338	)		(277	)
Changes in operating assets and liabilities
Accounts Receivable		(14,772	)		16,951
Inventory, Prepaid Expenses and Other Assets		1,118			1,024
Accounts Payable and Accrued Liabilities		10,425			(23,984	)
Other Assets and Liabilities		(676	)		(961	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(4,637	)		19,806
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		—			43
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		190			4,533
Proceeds from Joint Venture for Reimbursement of Capital Costs		19,461			16,611
Acquisitions of Undeveloped Acreage		(5,900	)		(21,114	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(37,738	)		(125,645	)
NET CASH USED IN INVESTING ACTIVITIES		(23,987	)		(125,572	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(15,230	)		(56,443	)
Proceeds from Long-Term Debt and Line of Credit		50,400			157,960
Repayments of Loans and Other Notes Payable		(361	)		(1,153	)
Debt Issuance Costs		(3,838	)		(572	)
Dividends Paid on Preferred Stock		—			(4,830	)
Distributions by the Partners of Consolidated Joint Ventures		—			(830	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		30,971			94,132
NET INCREASE (DECREASE) IN CASH		2,347			(11,634	)
CASH – BEGINNING		1,091			18,096
CASH – ENDING	$	3,438		$	6,462
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	$	3,438		$	6,113
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE	$	—		$	349
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	$	24,260		$	24,832
Cash Paid (Received) for Income Taxes	$	29		$	(502	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations	$	(991	)	$	(8,848	)
NON-CASH ACTIVITIES
Decrease in Accrued Liabilities for Capital Expenditures	$	(1,688	)	$	(9,044	)
Decrease in Senior Notes, Net of Issuance Costs due to Debt to Equity Conversions	$	(28,082	)	$	-
Decrease in Bond Interest Payable due to Debt to Equity Conversions	$	(719	)	$	-
Decrease in Premium on Senior Notes, Net due to Debt to Equity Conversions	$	(653	)	$	-
Increase in Common Stock outstanding due to Debt to Equity Conversions	$	5,696		$	-

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. We are focused on Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. 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. We report our interests in oil, NGL and natural gas properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

For purposes of compliance with Accounting Standards Update (“ASU”) 2015-3, which we adopted on January 1, 2016, we have reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and approximately $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. In addition, we adopted ASU 2015-17 on January 1, 2016, which eliminates the need to show deferred tax liabilities and assets as current and noncurrent. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero (see Note 5, Recently Issued Accounting Pronouncements, to our Consolidated Financial Statements for additional information). For purposes of consistency, we have reclassified $350.0 million and $325.0 million from 8.875% Senior Notes Due 2020 and 6.25% Senior Notes Due 2022, respectively, to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015.

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, 2015.

In June 2016, we entered into a purchase and sale agreement to divest all of our Illinois Basin assets and operations. The sale is currently expected to close in August 2016, with an effective date of July 1, 2016. As a result of this transaction, we have classified all assets of the Illinois Basin as “Held for Sale” as they represent a significant component of our operations, and our assets and operations in the Illinois Basin are reported as Discontinued Operations in the accompanying consolidated financial statements.

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.

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

Accretion expense totaled $0.1 million and $0.4 million for the three and six months ended June 30, 2016, respectively, and $0.3 million and $0.5 million for the three and six months ended June 30, 2015, 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.

¹ Includes approximately $0.3 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

In December 2014, our board of directors approved a formal plan to sell Water Solutions Holdings, LLC (“Water Solutions”), of which we owned 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 $66.8 million in net proceeds, resulting in a gain of approximately $57.8 million. The transaction was recorded as Discontinued Operations in 2015.

Summarized financial information for Discontinued Operations related to 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 June 30,					Six Months Ended June 30,
($ in Thousands)	2016		2015			2016		2015
Revenues:
Field Services Revenue	$	—	$	16,643		$	—	$	31,607
Total Operating Revenue		—		16,643			—		31,607
Costs and Expenses:
General and Administrative Expense		—		902			—		1,879
Depreciation, Depletion, Amortization and Accretion		—		37			—		76
Field Services Operating Expense		—		13,464			—		24,753
Gain on Sale of Asset		—		(10	)		—		(42	)
Interest Expense		—		240			—		431
Other Expense		—		17			—		120
Total Costs and Expenses		—		14,650			—		27,217
Income from Discontinued Operations Before Income Taxes		—		1,993			—		4,390
Income Tax (Expense) Benefit		—		101			—		(242	)
Income from Discontinued Operations, net of taxes	$	—	$	2,094		$	—	$	4,148

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell has agreed to purchase, subject to certain parameters and provisions for adjustment customary for transactions of this type, all of Rex’s oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing is expected to occur on or about August 16, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June, and we expect to receive the remaining proceeds of approximately $37.5 million at closing (subject to customary closing and post-closing adjustments). An additional agreement executed in conjunction with the Sales Agreement allows for Rex to receive from Campbell potential additional proceeds of up $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for each specific quarter.

Included in the sale are approximately 76,000 net acres in Illinois, Indiana and Kentucky; the assets are currently producing approximately 1,700 net barrels per day. This Purchase and Sale Agreement results in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations. As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale”, and our assets and operations in the Illinois Basin are reported as Discontinued Operations.

The carrying value of assets and liabilities of our Illinois Basin operations that are classified as Held for Sale in the accompanying Consolidated Balance Sheets at June 30, 2016 and December 31, 2015 are as follows:

	June 30,			December 31,
($ in Thousands)	2016			2015
Assets:
Accounts Receivable		2,367			2,209
Inventory, Prepaid Expenses and Other		1,023			770
Total Current Assets		3,390			2,979
Evaluated Oil & Gas Properties		297,222			296,338
Unevaluated Oil & Gas Properties		37			—
Other Property and Equipment		19,354			19,749
Wells and Facilities in Progress		3,401			3,456
Accumulated Depreciation, Depletion, and Amortization		(276,855	)		(262,071	)
Total Long-Term Assets		43,159			57,472
Total Assets Held for Sale	$	46,549		$	60,451
Liabilities:
Accounts Payable	$	4,831		$	1,089
Current Maturities of Long-Term Debt		85			188
Accrued Liabilities		3,285			3,718
Total Current Liabilities		8,201			4,995
Long-Term Debt		—			10
Future Abandonment Cost		31,734			31,315
Total Long-Term Liabilities		31,734			31,325
Total Liabilities Related to Assets Held for Sale	$	39,935		$	36,320
Net Assets Held for Sale	$	6,614		$	24,131

Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables 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. The sale of our Illinois assets and operations does not include any of our derivative contracts or positions related to our Illinois basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the three and six months periods ended June 30, 2016 and 2015.

	Three Months Ended June 30,						Six Months Ended June 30,
($ in Thousands)	2016			2015			2016			2015
Revenues:
Oil Sales	$	6,393		$	9,989		$	11,213		$	18,176
Total Operating Revenue		6,393			9,989			11,213			18,176
Costs and Expenses:
Production and Lease Operating Expense		5,029			6,372			10,725			12,307
General and Administrative Expense		659			1,086			1,437			2,385
(Gain) Loss on Disposal of Assets		(2	)		72			(43	)		73
Impairment Expense		—			3			3,543			178
Exploration Expense		85			162			143			241
Depreciation, Depletion, Amortization and Accretion		2,186			4,840			5,083			9,127
Interest Expense		1			13			3			17
Other Income		(2	)		(4	)		(3	)		(19	)
Total Costs and Expenses		7,956			12,544			20,888			24,309
Loss from Discontinued Operations Before Income Taxes		(1,563	)		(2,555	)		(9,675	)		(6,133	)
Income Tax (Expense) Benefit		(120	)		—			502			—
Loss from Discontinued Operations, net of taxes	$	(1,683	)	$	(2,555	)	$	(9,173	)	$	(6,133	)
Production:
Crude Oil (Bbls)		150,980			182,724			308,720			362,541

As described in Note 3 Discontinued Operations/Assets Held for Sale, we sold Water Solutions pursuant to a purchase and sale agreement with American Water.

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 in 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. As of June 30, 2016, ArcLight had paid approximately $61.4 million for their interest in wells that have been drilled. As of June 30, 2016, all wells to be developed with ArcLight had been drilled and completed with four wells remaining to be placed into service.

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.

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP will participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled, completed, placed in sales and paid for by BSP. The remaining four wells are expected to be placed in sales and paid for by BSP during the fourth quarter of 2016. BSP will also fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and for which final payment from BSP is expected during the third quarter of 2016. BSP also has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. During second quarter 2016, BSP exercised their option to participate in 16 of these additional wells, including four that were already drilled. We expect total consideration for this transaction to be $175.0 million with approximately $110.0 million committed as of June 30, 2016. BSP has paid approximately $24.6 million for their interest in elected wells as of June 30, 2016. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which they participate. As of June 30, 2016, 18 of the 38 elected wells were in line and producing, seven wells were drilled and awaiting completion and four wells were awaiting pipeline connection.

The BSP 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 BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized.

On May 20, 2016, we entered into a Purchase and Sale Agreement (“PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $51,000. Included in the sale are approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016, due to the elimination of our future abandonment liability associated with wells and pipelines sold to DOG. The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale.

As described in Note 3, Discontinued Operations/Assets Held for Sale, we have entered into a purchase and sale agreement for our Illinois Basin assets and operations as of June 30, 2016, with closing expected in August of 2016.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

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. We adopted this ASU on January 1, 2016. Adoption did not 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. We adopted this ASU on January 1, 2016. In conjunction with the adoption of ASU 2015-03, we reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. Adoption did not have an impact on Net Income or Accumulated Deficit.

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:

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:

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 November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. We adopted this ASU on January 1, 2016. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Deferred Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero. Adoption did not have an impact on Net Income or Accumulated Deficit.

In February 2016, the FASB issued ASU 2016-02, Leases. Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:

Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating this guidance and do not believe it will have a material impact due to our minimal number of operating leases.

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. Under this update, several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. We are currently evaluating the impact of this standard.

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, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the six months ended June 30, 2016, approximately 95.3% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 49.7% of commodity sales.

We maintain a revolving credit facility evidenced by a credit agreement, dated March 27, 2013 and most recently amended on July 1, 2016 (the “Senior Credit Facility”). As of June 30, 2016, the borrowing base under the Senior Credit Facility was $190.0 million. The Senior Credit Facility may be increased to up to $400.0 million upon redeterminations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a sub-facility exists for up to $60.0 million of letters of credit. Effective July 1, 2016, our borrowing base was reaffirmed at $190.0 million in connection with our scheduled redetermination. As of June 30, 2016, loans made under the Senior Credit Facility were set to mature on September 12, 2019. Our borrowing base is redetermined at least twice per year with the next redetermination scheduled to occur on or about October 1, 2016. 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 June 30, 2016, we had $146.7 million borrowings outstanding, and approximately $43.3 million in outstanding undrawn letters of credit. There were $111.5 million borrowings outstanding as of December 31, 2015. Our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million, with any excess to be used to pay down the outstanding Senior Credit Facility balance; however we retain the right to draw on the Senior Credit Facility so long as there are amounts available under our borrowing base.

The Senior Credit Facility requires we meet, on a quarterly basis, financial requirements including a minimum consolidated current ratio and maximum net senior secured debt to EBITDAX ratio. 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, including 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 June 30, 2016 was approximately 0.8 to 1.0. Due to our expectation that we would not be in compliance with the current ratio, we received a waiver of this requirement from our lenders for the period ended June 30, 2016 in conjunction with the most recent redetermination. We expect to be in compliance with the current ratio covenant at September 30, 2016 and beyond. 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 2.75 to 1.0. Our ratio of net senior secured debt to EBITDAX as of June 30, 2016 was approximately 2.4 to 1.0. In conjunction with the most recent redetermination, our lenders also added a requirement that beginning September 30, 2016, our ratio of “Total PDP PV-9” at the “Forward Strip Commodity Price” as of each date of determination to “Net Senior Secured Debt” (all terms in quotations as defined in the credit agreement) (the “PDP Coverage Ratio”) be at least 1.65 to 1.0. Additionally, requirements were added that limit our aggregate net capital expenditures during fiscal years 2016 and 2017 to $65 million on a rolling 12 month basis unless our PDP Coverage Ratio exceeds 2.0 to 1.0. Management currently anticipates being in compliance with these covenants at September 30, 2016 and beyond.

In order to improve our liquidity positions to meet the financial requirements under our Senior Credit Facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, including (i) debt-for-debt or debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing capital expenditures, (iv) asset sales, (v) improving cash flows from operations, (vi) effectively managing working capital, (vii) adding hedging positions, and (viii) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations.

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. See Note 9, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of New Notes and (ii) 8.4 million shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept Shares. In addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending October 1, 2020. In connection with the Exchange, we incurred approximately $0.5 million and $9.0 million in third-party debt issuance costs, in the three and six-month periods ending June 30, 2016, respectively. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations.

Following the completion of the Exchange, we entered into debt-for equity exchanges with certain holders of our Existing Notes, as well as holders of our New Notes, in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of $26.9 million of our outstanding Existing Notes and $2.2 million of our outstanding New Notes, in exchange for the issuance of a total of approximately 5.2 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the company of approximately $23.7 million, presented as Gain on Extinguishment of Debt in our Consolidated Statement of Operations for the three and six month periods ending June 30, 2016.

We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Existing Notes and the New Notes from the holders.

Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets.

The Senior Notes are represented by indentures (the “Indentures”), which 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 Senior Notes 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 to 1.00. As of June 30, 2016, our Fixed Charge Coverage Ratio was 1.16 to 1.00. We expect our Fixed Charge Coverage Ratio to improve in 2016 based on our projections of decreased interest expense related to the New Notes. As of June 30, 2016, we were limited to incurring an additional $148.6 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual Trustees or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

As of June 30, 2016 and December 31, 2015, we had recorded on our Consolidated Balance Sheets approximately $1.5 million and $2.3 million, respectively, of a net premium related to the Senior Notes. The amortization of our net premium during the three and six-month periods ended June 30, 2016, which follows the effective interest method, was approximately $0.1 million and $0.2 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 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 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year.

In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at June 30, 2016 and December 31, 2015:

The following is the principal maturity schedule for debt outstanding as of June 30, 2016:

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 June 30, 2016 and December 31, 2015, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, 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 $17.4 million and $30.5 million in relation to our commodity derivatives during the three and six months ended June 30, 2016, respectively, and received net cash settlements of $13.5 million and $24.1 million in relation to our commodity derivatives during the three and six months ended June 30, 2015, respectively.

As of June 30, 2016, we had over 100.0% of our annualized condensate production hedged through the remainder of 2016, over 90.0% and 50.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 50.0% of our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our Illinois Basin production and basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our natural gas, condensate and NGL production.

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 June 30, 2016, and December 31, 2015, we had $146.7 million and $111.5 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $646.4 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 June 30, 2016 and December 31, 2015, 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 six months ended June 30, 2015, we received cash payments of approximately $0.4 million and $0.9 million, respectively, related to our 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 six months ended June 30, 2016 and 2015:

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $19.7 million and a net asset of approximately $35.8 million at June 30, 2016 and December 31, 2015, respectively.

Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2016 consisted of:

Period	Volume	Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2016 - Collars	272,000 Bbls	$	—	$	38.05	$	49.15	$	—		$	(956	)
2016 - Three-Way Collars	150,000 Bbls		31.20		41.40		49.60		—			(442	)
2016 - Cap Swaps	60,000 Bbls		30.00		—		—		44.00			(361	)
	482,000 Bbls										$	(1,759	)
Natural Gas
2016 - Swaps	8,155,000 Mcf		—		—		—		2.54		$	(3,475	)
2016 - Swaptions	600,000 Mcf		—		—		—		3.15			79
2016 - Cap Swaps	2,400,000 Mcf		2.59		—		—		3.07			(612	)
2016 - Collars	2,110,000 Mcf		—		2.63		3.03		—			(409	)
2016 - Three-Way Collars	1,505,000 Mcf		2.11		2.68		3.30		—			(377	)
2016 - Put Spreads	6,015,000 Mcf		2.51		3.27		—		—			760
2016 - Basis Swaps - Dominion South	11,113,000 Mcf		—		—		—		(0.88	)		(139	)
2017 - Swaps	2,460,000 Mcf		—		—		—		3.21			178
2017 - Swaptions	0 Mcf		—		—		—		—			(670	)
2017 - Cap Swaps	3,900,000 Mcf		2.35		—		—		2.81			(1,559	)
2017 - Three-Way Collars	16,900,000 Mcf		2.32		3.01		3.87		—			594
2017 - Calls	3,000,000 Mcf		—		—		3.64		—			(1,277	)
2017 - Collars	1,400,000 Mcf		—		2.40		3.10		—			(348	)
2017 - Basis Swaps - Dominion South	4,550,000 Mcf		—		—		—		(0.83	)		(1,073	)
2017 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(372	)
2018 - Swaps	960,000 Mcf		—		—		—		3.25			495
2018 - Swaptions	0 Mcf		—		—		—		—			(320	)
2018 - Three-Way Collars	7,875,000 Mcf		2.29		2.88		3.56		—			(755	)
2018 - Calls	5,810,000 Mcf		—		—		3.97		—			(485	)
2018 - Basis Swaps - Dominion South	6,400,000 Mcf		—		—		—		(0.83	)		(1,073	)
2018 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(372	)
2019 - Basis Swaps - Dominion South	7,300,000 Mcf		—		—		—		(0.83	)		(1,073	)
2020 - Basis Swaps - Dominion South	7,320,000 Mcf		—		—		—		(0.83	)		(1,073	)
	128,973,000 Mcf										$	(13,356	)
NGLs
2016 - C3+ NGL Swaps	714,000 Bbls		—		—		—		26.04		$	(261	)
2016 - Ethane Swaps	330,000 Bbls		—		—		—		8.40			(766	)
2017 - C3+ NGL Swaps	468,000 Bbls		—		—		—		20.16			(2,228	)
2017 - Ethane Swaps	540,000 Bbls		—		—		—		10.08			(1,220	)
	2,052,000 Bbls										$	(4,475	)
Refined Product (Heating Oil)
2016 - Swaps	6,000 Bbls	$	—	$	—	$	—	$	84.00		$	(117	)
	6,000 Bbls										$	(117	)

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015 is summarized below:

	June 30,			December 31,
($ in Thousands)	2016			2015
Short-Term Derivative Assets:
Crude Oil—Collars	$	—		$	1,078
Crude Oil—Deferred Put Spread		—			852
Crude Oil—Three-Way Collars		355			577
NGL—Swaps		1,127			10,250
Natural Gas—Swaps		879			9,010
Natural Gas—Cap Swaps		334			1,977
Natural Gas—Basis Swaps		397			70
Natural Gas—Three-Way Collars		783			6,183
Natural Gas—Collars		—			1,728
Natural Gas—Swaption		79			798
Natural Gas—Put Spread		806			1,737
Total Short-Term Derivative Assets	$	4,760		$	34,260
Long-Term Derivative Assets:
NGL—Swaps	$	—		$	344
Natural Gas—Cap Swaps		—			2,294
Natural Gas—Swaps		743			1,593
Natural Gas—Basis Swaps		—			195
Natural Gas—Three-Way Collars		783			5,108
Total Long-Term Derivative Assets	$	1,526		$	9,534
Total Derivative Assets	$	6,286		$	43,794
Short-Term Derivative Liabilities:
Crude Oil—Three-Way Collars		(797	)		—
Crude Oil—Collars		(956	)		—
Crude Oil—Deferred Put Spread		(361	)		—
NGL—Swaps		(3,878	)		—
Refined Product—Swaps		(117	)		(376	)
Natural Gas—Three-Way Collars		(973	)		(31	)
Natural Gas—Collars		(558	)		—
Natural Gas—Basis Swaps		(1,258	)		(1,585	)
Natural Gas—Put Spread		(46	)		—
Natural Gas—Call		(639	)		—
Natural Gas—Swaption		(326	)		(202	)
Natural Gas—Swaps		(4,323	)		(292	)
Natural Gas—Cap Swaps		(1,670	)		—
Total Short - Term Derivative Liabilities	$	(15,902	)	$	(2,486	)
Long-Term Derivative Liabilities:
NGL—Swaps		(1,724	)		—
Natural Gas—Swaps		(101	)		—
Natural Gas—Swaption		(664	)		(297	)
Natural Gas—Basis Swaps		(4,314	)		(4,186	)
Natural Gas—Collars		(199	)		—
Natural Gas—Call		(1,123	)		(989	)
Natural Gas—Cap Swaps		(835	)		—
Natural Gas—Three-Way Collars		(1,131	)		(84	)
Total Long-Term Derivative Liabilities	$	(10,091	)	$	(5,556	)
Total Derivative Liabilities	$	(25,993	)	$	(8,042	)

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.

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 June 30, 2016 and December 31, 2015, 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 June 30, 2016 and December 31, 2015, 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 June 30, 2016 and December 31, 2015 are included in the table below.

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 six months ended June 30, 2016 and for the year ended December 31, 2015, 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:

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 June 30, 2016 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 June 30, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of June 30, 2016 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 six months ended June 30, 2016 and 2015:

Changes in fair value on our Level 3 commodity derivative contracts outstanding for the six months ended June 30, 2016 and 2015, resulted in a decrease of approximately $1.4 million and an increase of approximately $3.4 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

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.

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

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.

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.

During the six months ended June 30, 2016, we recorded an other than temporary impairment of $35.8 million related to proved and unproved properties. 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.

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.

For the six months ended June 30, 2016 and 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 June 30, 2016 and 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. As a result of the Senior Note Exchange completed on March 31, 2016, we generated approximately $543.2 million of taxable Cancellation of Debt Income (“CODI”) income, which is calculated by comparing the fair value of the New Notes and the face value of the Existing Notes exchanged. In the second quarter of 2016, we completed debt-to-equity exchanges with certain holders of our Senior Notes, resulting in taxable losses and reductions of our current year CODI income of approximately $2.0 million. See Note 7, Long-Term Debt, to our Consolidated Financial Statements, for additional information on our debt for equity exchanges. We expect to offset this income by utilizing our net operating loss carryforwards and through the effect of interest expense amortizations of the Original Issue Discount generated by the Exchange transactions. As of June 30, 2016 we have projected and recorded an alternative minimum tax liability of approximately $2.1 million and state income taxes payable of approximately $0.2 million, classified as Accrued Liabilities on our Consolidated Balance Sheet.

Income tax payments made during the six months ended June 30, 2016 and 2015 were negligible. Tax refunds received during the six months ended June 30, 2016 were negligible, and refunds of approximately $0.5 million were received during the six months ended June 30, 2015.

On May 27, 2016, the Company’s common shareholders approved an increase in the number of authorized shares from 100,000,000 to 200,000,000 common shares. As of June 30, 2016, we have authorized capital stock of 200,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2016 and December 31, 2015, shares of common stock issued and outstanding totaled 78,440,589 and 55,741,229, respectively. During the six-month period ending June 30, 2016, we issued approximately 8.4 million shares of our common stock in conjunction with the Exchange completed on March 31, 2016, and approximately 5.2 million shares of our common stock in debt-to-equity exchanges with certain holders of our Senior Notes. See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information regarding our debt and equity exchanges.

As of June 30, 2016 and December 31, 2015, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”) issued and outstanding totaled 4,087 and 16,100, respectively. During the six months ended June 30, 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 9.0 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. See Note 13, Earnings Per Common Share, to our Consolidated Financial Statements, for additional information regarding the effect of the preferred stock conversions on Net Income (Loss) Attributable to Common Shareholders.

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 from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. No dividend has been declared by our board of directors in 2016. As of June 30, 2016 accumulated dividends in arrears totaled $3.8 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulated dividends are added to our Net Loss in the determination of Loss Attributable to Common Shareholders and related loss per share calculations.

In 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, May 15, 2015 to August 15, 2015, and August 15, 2015 to November 15, 2015, respectively, each in the aggregate amount of $2.4 million. If we do not pay dividends for an aggregate of six quarterly periods, the holders of the shares of Series A Preferred Stock will have the right to elect two additional directors to serve on our board of directors.

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.

During the six-month period ended June 30, 2016, we issued 888,922 options to purchase shares of our common stock to 34 employees. During the six-month period ended June 30, 2015, we issued 80,000 options to purchase shares of our common stock to 3 employees. Stock-based compensation expense relating to stock options outstanding for each of the three and six months ended June 30, 2016 and 2015 was $0.1 million. Stock-based compensation relating to stock options outstanding for the three and six month periods ended June 30, 2015 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. There were no stock options exercised for the six months ended June 30, 2016. There was no tax benefit related to stock option exercises for each of the six-month periods ended June 30, 2016 and 2015.

A summary of the status of our issued and outstanding stock options as of June 30, 2016 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding At 6/30/16		Weighted-Average Exercise Price		Number Exercisable At 6/30/16		Weighted-Average Exercise Price
$	0.97		37,500	$	0.97		—	$	0.97
$	1.69		826,800	$	1.69		—	$	1.69
$	4.05		40,000	$	4.05		—	$	4.05
$	4.90		40,000	$	4.90		3,333	$	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
$	13.19		50,000	$	13.19		50,000	$	13.19
$	22.34		30,000	$	22.34		30,000	$	22.34
			1,304,472	$	4.35		363,505	$	10.71

The weighted average remaining contractual term for options outstanding at June 30, 2016 was 5.2 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at June 30, 2016 was 1.5 years and there was no aggregate intrinsic value. As of June 30, 2016, unrecognized compensation expense related to stock options was $0.5 million.

During the six-month period ended June 30, 2016, the Compensation Committee approved the issuance of an aggregate of 428,826 shares of restricted common stock to 25 employees. During the six-month period ended June 30, 2015, the Compensation Committee approved the issuance of an aggregate of 1,351,497 shares of restricted stock to 127 employees, one director and one non-employee contractor. Certain of our outstanding restricted stock awards granted in 2015 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.

The weighted average fair value of the TSR awards granted as December 31, 2015 was $2.56 per share. There have been no TSR awards granted in 2016. 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:

Compensation expense from restricted stock awards associated with our continuing operations totaled $1.1 million and $0.9 million for the three and six-month periods ended June 30, 2016, respectively, and $1.8 million and $4.6 million for the three and six-month periods ended June 30, 2015, respectively. During the first quarter of 2016, 235,573 performance stock awards were forfeited due to not meeting specified targets, which resulted in a one-time reduction to expense of approximately $1.5 million. 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 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of June 30, 2016, total unrecognized compensation cost related to restricted common stock grants was approximately $2.8 million, which will be recognized over a weighted average period of 1.3 years.

A summary of the restricted stock activity for the six months ended June 30, 2016 is as follows:

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 then 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, 2015.

In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 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 complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte if one were certified. 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 both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated.

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. In June 2016, we and the plaintiffs each presented our arguments on the appeal before a three-judge panel of the Pennsylvania Superior Court. To date, the court has not ruled on the appeal. We expect to receive the court’s ruling on the appeal in the second half of 2016.

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.

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

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of June 30, 2016, we know of no significant probable or possible environmental contingent liabilities.

At June 30, 2016, we had posted $43.3 million in various letters of credit to secure our drilling and related operations.

As of June 30, 2016, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2016, was approximately $0.3 million and $0.6 million, respectively, and $0.3 million and $0.5 million for the three and six months ended June 30, 2015, respectively. Lease commitments by year for each of the next five years are presented in the table below:

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 utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $7.3 million in 2016, $16.5 million in 2017, $16.5 million in 2018, $16.5 million in 2019, $16.5 million in 2020 and $97.6 million thereafter, assuming our average net revenue interest in the region of approximately 53%. Charges incurred for unutilized processing capacity with MarkWest during the three and six-month periods ended June 30, 2016 were $0.8 million and $1.4 million, respectively, and $0.2 million and $0.4 million for the three and six-month periods ended June 30, 2015, respectively.

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 $1.1 million in 2016, $2.3 million in 2017 and $0.3 million in 2018, 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 as of June 30, 2015. Approximately $2.3 million of this amount was paid in January 2015 and $2.5 million 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 $0.5 million in 2016, which would be partially offset by other working interest owners, which vary from well to well.

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 natural gas, NGLs and condensate. 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 $414.0 million through 2029.

For the three and six months ended June 30, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $21.8 million and $43.3 million in 2016, respectively, and $20.5 million and $39.4 million in 2015, 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 six months ended June 30, 2016 and 2015, we incurred approximately $0.7 million and $1.0 million in 2016, respectively, and $0.2 million and $0.4 million in 2015, 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 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:

^(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 six months ended June 30, 2016 and 2015, we recorded expense of approximately $0.8 million and $1.3 million in 2016, respectively, and $0.8 million and $1.5 million in 2015, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of June 30, 2016, approximately $1.3 million was accrued for 2016 impact fees.

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 six months ended June 30, 2016 and 2015, we excluded stock options to purchase 1.3 million shares and 0.5 million shares of our common stock, respectively, due to our Net Loss from Continuing Operations. For the three and six months ended June 30, 2016 and 2015, we excluded performance-based restricted stock of 0.7 million shares and 1.3 million shares, respectively, 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). 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 six-month periods ended June 30, 2016 and June 30, 2015, we excluded the assumed conversion of preferred stock equating to approximately 2.3 million shares and 8.9 million shares, respectively, due to our Net Loss from Continuing Operations. We included in Net Income (Loss) Attributable to Common Shareholders the effect of the preferred share to common share conversions completed during the three and six months ended June 30, 2016. The conversions completed during these periods resulted in an increase in Net Income (decrease in Net Loss) Attributable to Common Shareholders of approximately $72.3 million, representing the carrying value of the preferred shares converted in excess of the fair value of the common shares issued in the conversions. The following table sets forth the computation of basic and diluted earnings per common share:

(in thousands, except per share amounts)	Three Months Ended June 30,						Six Months Ended June 30,
Numerator:	2016			2015			2016			2015
Net Loss From Continuing Operations	$	(52,911	)	$	(151,342	)	$	(105,562	)	$	(166,335	)
Net Loss From Discontinued Operations, Less Noncontrolling Interests		(1,683	)		(1,410	)		(9,173	)		(4,231	)
Less: Preferred Stock Dividends		(1,723	)		(2,415	)		(3,828	)		(4,830	)
Effect of Preferred Stock Conversions		72,316			—			72,316			—
Net Income (Loss) Attributable to Common Shareholders	$	15,999		$	(155,167	)	$	(46,247	)	$	(175,396	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		71,804			54,118			64,044			54,090
Effect of Dilutive Securities:
Employee Stock Options		—			—			—			—
Employee Performance-Based Restricted Stock Awards		—			—			—			—
Effect of Assumed Conversions of Preferred Stock		—			—			—			—
Weighted Average Common Shares Outstanding - Diluted		71,804			54,118			64,044			54,090
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Income (Loss) From Continuing Operations	$	0.24		$	(2.84	)	$	(0.58	)	$	(3.16	)
— Net Loss From Discontinued Operations		(0.02	)		(0.03	)		(0.14	)		(0.08	)
— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.22		$	(2.87	)	$	(0.72	)	$	(3.24	)
Diluted — Net Income (Loss) From Continuing Operations	$	0.24		$	(2.84	)	$	(0.58	)	$	(3.16	)
— Net Loss From Discontinued Operations		(0.02	)		(0.03	)		(0.14	)		(0.08	)
— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.22		$	(2.87	)	$	(0.72	)	$	(3.24	)

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our natural gas operations. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering. We did not make any capital contributions to RW Gathering during the first six months of 2016 and 2015. RW Gathering recorded net losses from continuing operations of $0.5 million and $1.0 million during the three and six-month periods ended June 30, 2016, respectively, as compared to losses of $0.5 million and $1.0 million for the comparable periods in 2015. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Historically, we 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 net losses due to our investment being reduced to zero.

During the three and six-month periods ended June 30, 2016 we incurred approximately $0.1 million and $0.3 million, respectively, as compared to $0.2 million and $0.4 million for the three and six-month periods ended June 30, 2015, 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 June 30, 2016 and December 31, 2015, there were no receivables or payables due between RW Gathering and us.

For the three and six months ended June 30, 2016, impairment expenses incurred were approximately $25.1 million and $35.8 million, respectively, and impairment expenses incurred for the three and six-month periods ended June 30, 2015 were approximately $117.8 million and $124.7 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first six months of 2016 included approximately $34.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Impairments of proved properties in our Butler County operations totaled approximately $1.0 million during the first six months of 2016. 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 and future development plans. Our estimates of future cash flows attributable to our oil and gas properties could decline if commodity prices decline, which may result in our incurrence of additional impairment expense. As of June 30, 2016, we continued to carry the costs of undeveloped properties of approximately $232.7 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we have development, trade or lease extension plans.

The expense incurred during the first six months of 2015 included proved properties in our non-operated dry gas regions of Clearfield County, Pennsylvania and Westmoreland County, Pennsylvania for approximately $73.4 million. In addition to the proved properties, we also incurred approximately $31.6 million in impairment related to unproved properties, the majority of which are also found in our non-operated dry gas regions of Clearfield and Westmoreland Counties, Pennsylvania, and $17.5 million related to our equity method investment in RW Gathering. The remaining 2015 impairments are primarily related to acreage expirations and pipelines in non-core areas.

For the three and six months ended June 30, 2016, we incurred approximately $0.8 million and $1.7 million, respectively, in exploration expenses as compared to $0.8 million and $1.2 million in exploration expenses for the same periods in 2015, respectively. Approximately $0.9 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and the remaining $0.8 million was due to costs associated with exploratory wells that were abandoned at various stages resulting in dry hole expense. Approximately $0.5 million of the expense incurred in 2015 was due to geological and geophysical type expenditures. An additional $0.5 million of expense was incurred through the payment of delay rentals, and the remaining 2015 expense of $0.2 million was due to costs associated with exploratory wells that were abandoned at various stages resulting in dry hole expense.

As of June 30, 2016, we had an aggregate of $646.4 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 Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of June 30, 2016:

The non-guarantor subsidiaries include certain consolidated subsidiaries, including 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 June 30, 2016, 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 June 30, 2016 and December 31, 2015, the condensed consolidating statements of operations for each of the three and six-month periods ended June 30, 2016 and 2015, and the condensed consolidating statements of cash flows for each of the six-month periods ended June 30, 2016 and 2015.

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,435		$	—		$	3		$	—		$	3,438
Accounts Receivable		27,694			—			3,950			—			31,644
Taxes Receivable		—			—			48			—			48
Short-Term Derivative Instruments		4,760			—			—			—			4,760
Inventory, Prepaid Expenses and Other		1,688			—			—			—			1,688
Assets Held for Sale		45,466			1,083			—			—			46,549
Total Current Assets		83,043			1,083			4,001			—			88,127
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,020,936			—			—						1,020,936
Unevaluated Oil and Gas Properties		232,674			—			—			—			232,674
Other Property and Equipment		21,444			—			—			—			21,444
Wells and Facilities in Progress		75,992			—			—			—			75,992
Pipelines		14,144			—			—			—			14,144
Total Property and Equipment		1,365,190			—			—			—			1,365,190
Less: Accumulated Depreciation, Depletion and Amortization		(459,427	)		—			—			—			(459,427	)
Net Property and Equipment		905,763			—			—			—			905,763
Other Assets		2,490			—			—			—			2,490
Intercompany Receivables		—			—			1,071,155			(1,071,155	)		—
Investment in Subsidiaries – Net		(2,388	)		—			(127,974	)		130,362			—
Long-Term Derivative Instruments		1,526			—			—			—			1,526
Total Assets	$	990,434		$	1,083		$	947,182		$	(940,793	)	$	997,906
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	51,915		$	—		$	—		$	—		$	51,915
Current Maturities of Long-Term Debt		172			—			—			—			172
Accrued Liabilities		24,498			—			5,848						30,346
Short-Term Derivative Instruments		15,902			—			—			—			15,902
Liabilities Related to Assets Held for Sale		39,903			32			—			—			39,935
Total Current Liabilities		132,390			32			5,848			—			138,270
Long-Term Derivative Instruments		10,091			—			—			—			10,091
Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs		—			—			141,237			—			141,237
Senior Notes, Net of Issuance Costs		—			—			637,314			—			637,314
Premium on Senior Notes – Net		—			—			1,524			—			1,524
Other Deposits and Liabilities		2,860			—			—			—			2,860
Future Abandonment Cost		7,313			418			—			—			7,731
Intercompany Payables		1,066,506			4,649			—			(1,071,155	)		—
Total Liabilities		1,219,160			5,099			785,923			(1,071,155	)		939,027
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			77			—			77
Additional Paid-In Capital		177,144			—			637,223			(177,144	)		637,223
Accumulated Earnings (Deficit)		(405,870	)		(4,016	)		(476,042	)		307,506			(578,422	)
Total Stockholders’ Equity		(228,726	)		(4,016	)		161,259			130,362			58,879
Total Liabilities and Stockholders’ Equity	$	990,434		$	1,083		$	947,182		$	(940,793	)	$	997,906

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	31,271		$	—		$	—		$	—	$	31,271
Other Revenue (Expense)		(6	)		—			—			—		(6	)
TOTAL OPERATING REVENUE		31,265			—			—			—		31,265
OPERATING EXPENSES
Production and Lease Operating Expense		25,221			—			—			—		25,221
General and Administrative Expense		3,661			—			1,176			—		4,837
Gain on Disposal of Assets		(4,307	)		—			—			—		(4,307	)
Impairment Expense		25,139			—			—			—		25,139
Exploration Expense		803			—			—			—		803
Depreciation, Depletion, Amortization and Accretion		14,747			3			—			—		14,750
Other Operating Expense		704			—			—			—		704
TOTAL OPERATING EXPENSES		65,968			3			1,176			—		67,147
LOSS FROM OPERATIONS		(34,703	)		(3	)		(1,176	)		—		(35,882	)
OTHER INCOME (EXPENSE)
Interest Expense		(269	)		—			(11,170	)		—		(11,439	)
Loss on Derivatives, Net		(29,169	)		—			—			—		(29,169	)
Other Income		12			—			—			—		12
Debt Exchange Expense		—			—			(533	)		—		(533	)
Gain on Extinguishment of Debt		—			—			23,707			—		23,707
Income (Loss) From Equity in Consolidated Subsidiaries		(54	)		54			(65,341	)		65,341		—
TOTAL OTHER INCOME (EXPENSE)		(29,480	)		54			(53,337	)		65,341		(17,422	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(64,183	)		51			(54,513	)		65,341		(53,304	)
Income Tax (Expense) Benefit		473			—			(80	)		—		393
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(63,710	)		51			(54,593	)		65,341		(52,911	)
Loss From Discontinued Operations, Net of Income Taxes		(1,629	)		(54	)		—			—		(1,683	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		(65,339	)		(3	)		(54,593	)		65,341		(54,594	)
Preferred Stock Dividends		—			—			(1,723	)		—		(1,723	)
Effect of Preferred Stock Conversions		—			—			72,316					72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(65,339	)	$	(3	)	$	16,000		$	65,341	$	15,999

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	56,944		$	—		$	—		$	—	$	56,944
Other Revenue		7			—			—			—		7
TOTAL OPERATING REVENUE		56,951			—			—			—		56,951
OPERATING EXPENSES
Production and Lease Operating Expense		49,671			1			—			—		49,672
General and Administrative Expense		9,080			—			1,041			—		10,121
Gain on Disposal of Assets		(4,295	)		—			—			—		(4,295	)
Impairment Expense		35,780			—			—			—		35,780
Exploration Expense		1,737			1			—			—		1,738
Depreciation, Depletion, Amortization and Accretion		31,249			13			—			—		31,262
Other Operating Expense		1,030			—			—			—		1,030
TOTAL OPERATING EXPENSES		124,252			15			1,041			—		125,308
LOSS FROM OPERATIONS		(67,301	)		(15	)		(1,041	)		—		(68,357	)
OTHER INCOME (EXPENSE)
Interest Expense		(539	)		—			(23,930	)		—		(24,469	)
Loss on Derivatives, Net		(25,120	)		—			—			—		(25,120	)
Other Income		12			—			—			—		12
Debt Exchange Expense		—			—			(9,014	)		—		(9,014	)
Gain on Extinguishment of Debt		—			—			23,707			—		23,707
Income (Loss) From Equity in Consolidated Subsidiaries		79			(79	)		(104,226	)		104,226		—
TOTAL OTHER INCOME (EXPENSE)		(25,568	)		(79	)		(113,463	)		104,226		(34,884	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(92,869	)		(94	)		(114,504	)		104,226		(103,241	)
Income Tax Expense		(2,090	)		—			(231	)		—		(2,321	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		(94,959	)		(94	)		(114,735	)		104,226		(105,562	)
Loss From Discontinued Operations, Net of Income Tax		(9,106	)		(67	)		—			—		(9,173	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(104,065	)	$	(161	)	$	(114,735	)	$	104,226	$	(114,735	)
Preferred Stock Dividends		—			—			(3,828	)		—		(3,828	)
Effect of Preferred Stock Conversions		—			—			72,316			—		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(104,065	)	$	(161	)	$	(46,247	)	$	104,226	$	(46,247	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(104,065	)	$	(161	)	$	(114,735	)	$	104,226		$	(114,735	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)		(100	)		—			10,200			—			10,100
Depreciation, Depletion, Amortization and Accretion		36,293			52			—			—			36,345
Gain on Derivatives		25,120			—			—			—			25,120
Cash Settlements of Derivatives		30,340			—			—			—			30,340
Dry Hole Expense		870			—			—			—			870
Gain on Sale of Asset		(4,338	)		—			—			—			(4,338	)
Gain on Extinguishment Debt		—			—			(23,757	)		—			(23,757	)
Impairment Expense		39,330			(7	)		39,323			(39,323	)		39,323
Changes in operating assets and liabilities
Accounts Receivable		(14,452	)		103			(423	)		—			(14,772	)
Inventory, Prepaid Expenses and Other Assets		1,093			—			25			—			1,118
Accounts Payable and Accrued Liabilities		15,148			—			(4,723	)		—			10,425
Other Assets and Liabilities		(651	)		(25	)		—			—			(676	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		24,588			(38	)		(94,090	)		64,903			(4,637	)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		2,035			109			62,759			(64,903	)		—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		190			—			—			—			190
Proceeds from Joint Venture		19,461			—			—			—			19,461
Acquisitions of Undeveloped Acreage		(5,863	)		(37	)		—			—			(5,900	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(37,704	)		(34	)		—			—			(37,738	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(21,881	)		38			62,759			(64,903	)		(23,987	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			—			50,400			—			50,400
Repayments of Long-Term Debt and Lines of Credit		—			—			(15,230	)		—			(15,230	)
Repayments of Loans and Other Long-Term Debt		(361	)		—			—			—			(361	)
Debt Issuance Costs		—			—			(3,838	)		—			(3,838	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(361	)		—			31,332			—			30,971
NET INCREASE IN CASH		2,346			—			1			—			2,347
CASH – BEGINNING		1,089			—			2			—			1,091
CASH - ENDING	$	3,435		$	—		$	3		$	—		$	3,438

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,089		$	—	$	2		$	—		$	1,091
Accounts Receivable		17,225			—		49			—			17,274
Taxes Receivable		—			—		18			—			18
Short-Term Derivative Instruments		34,260			—		—			—			34,260
Inventory, Prepaid Expenses and Other		3,034			—		25			—			3,059
Assets Held for Sale		59,411			1,040		—			—			60,451
Total Current Assets		115,019			1,040		94			—			116,153
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		950,062			—		—			(6,970	)		943,092
Unevaluated Oil and Gas Properties		262,992			—		—			—			262,992
Other Property and Equipment		20,363			—		—			—			20,363
Wells and Facilities in Progress		141,370			—		—			(270	)		141,100
Pipelines		16,161			—		—			(2,137	)		14,024
Total Property and Equipment		1,390,948			—		—			(9,377	)		1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(441,346	)		—		—			3,518			(437,828	)
Net Property and Equipment		949,602			—		—			(5,859	)		943,743
Deferred Financing Costs and Other Assets—Net		2,501			—		—			—			2,501
Intercompany Receivables		—			—		1,070,548			(1,070,548	)		—
Investment in Subsidiaries – Net		(1,907	)		—		243,331			(241,424	)		—
Long-Term Derivative Instruments		9,534			—		—			—			9,534
Total Assets	$	1,074,749		$	1,040	$	1,313,973		$	(1,317,831	)	$	1,071,931
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	36,785		$	—	$	—		$	—		$	36,785
Current Maturities of Long-Term Debt		402			—		—			—			402
Accrued Liabilities		28,883			—		11,725			—			40,608
Short-Term Derivative Instruments		2,486			—		—			—			2,486
Liabilities Related to Assets Held for Sale		36,289			31		—			—			36,320
Total Current Liabilities		104,845			31		11,725			—			116,601
Long-Term Derivative Instruments		5,556			—		—			—			5,556
Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs		28			—		109,358			—			109,386
Senior Notes, Net of Issuance Costs		—			—		663,089			—			663,089
Premium on Senior Notes – Net		—			—		2,344			—			2,344
Other Deposits and Liabilities		3,156			—		—			—			3,156
Future Abandonment Cost		11,159			409		—			—			11,568
Intercompany Payables		1,070,096			452		—			(1,070,548	)		—
Total Liabilities		1,194,840			892		786,516			(1,070,548	)		911,700
Stockholders’ Equity
Preferred Stock		—			—		1			—			1
Common Stock		—			—		54			—			54
Additional Paid-In Capital		177,143			—		619,777			(173,057	)		623,863
Accumulated Earnings (Deficit)		(297,234	)		148		(92,375	)		(74,226	)		(463,687	)
Total Stockholders’ Equity		(120,091	)		148		527,457			(247,283	)		160,231
Total Liabilities and Stockholders’ Equity	$	1,074,749		$	1,040	$	1,313,973		$	(1,317,831	)	$	1,071,931

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	35,772		$	—		$	—		$	—		$	35,772
Other Revenue		12			—			—			—			12
TOTAL OPERATING REVENUE		35,784			—			—			—			35,784
OPERATING EXPENSES
Production and Lease Operating Expense		24,270			—			—			—			24,270
General and Administrative Expense		5,576			—			1,818			—			7,394
Gain on Disposal of Asset		(373	)		—			—			—			(373	)
Impairment Expense		117,839			—			—			—			117,839
Exploration Expense		760			—			—			(5	)		755
Depreciation, Depletion, Amortization and Accretion		24,962			—			—			(264	)		24,698
Other Operating Income		(66	)		—			—			—			(66	)
TOTAL OPERATING EXPENSES		172,968			—			1,818			(269	)		174,517
INCOME (LOSS) FROM OPERATIONS		(137,184	)		—			(1,818	)		269			(138,733	)
OTHER INCOME (EXPENSE)
Interest Expense		(71	)		—			(12,110	)		—			(12,181	)
Gain (Loss) on Derivatives, Net		198			—			(479	)		—			(281	)
Other Income		61			—			—			—			61
Loss From Equity Method Investments		(208	)		—			—			—			(208	)
Income (Loss) From Equity in Consolidated Subsidiaries		3			(3	)		(138,226	)		138,226			—
TOTAL OTHER INCOME (EXPENSE)		(17	)		(3	)		(150,815	)		138,226			(12,609	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(137,201	)		(3	)		(152,633	)		138,495			(151,342	)
Income Tax (Expense) Benefit		119			—			(119	)		—			—
INCOME (LOSS) FROM CONTINUING OPERATIONS		(137,082	)		(3	)		(152,752	)		138,495			(151,342	)
Income From Discontinued Operations, Net of Income Tax		(2,033	)		2,824			—			(1,252	)		(461	)
Net Income (Loss)		(139,115	)		2,821			(152,752	)		137,243			(151,803	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			949			—			—			949
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(139,115	)	$	1,872		$	(152,752	)	$	137,243		$	(152,752	)
Preferred Stock Dividends		—			—			(2,415)			—			(2,415)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(139,115	)	$	1,872		$	(155,167	)	$	137,243		$	(155,167	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	81,696		$	—		$	—		$	—		$	81,696
Other Revenue		22			—			—			—			22
TOTAL OPERATING REVENUE		81,718			—			—			—			81,718
OPERATING EXPENSES
Production and Lease Operating Expense		47,387			—			—			—			47,387
General and Administrative Expense		11,082			—			4,663			—			15,745
Gain on Disposal of Asset		(309	)		—			—			—			(309	)
Impairment Expense		124,687			—			—			—			124,687
Exploration Expense		1,198			1			—			(5	)		1,194
Depreciation, Depletion, Amortization and Accretion		47,035			1			—			(499	)		46,537
Other Operating Expense		5,138			—			—			—			5,138
TOTAL OPERATING EXPENSES		236,218			2			4,663			(504	)		240,379
INCOME (LOSS) FROM OPERATIONS		(154,500	)		(2	)		(4,663	)		504			(158,661	)
OTHER INCOME (EXPENSE)
Interest Expense		(124	)		—			(24,069	)		—			(24,193	)
Gain (Loss) on Derivatives, Net		17,054			—			(216	)		—			16,838
Other Income		92			—			—			—			92
Loss From Equity Method Investments		(411	)		—			—			—			(411	)
Income (Loss) From Equity in Consolidated Subsidiaries		(20	)		20			(141,440	)		141,440			—
TOTAL OTHER INCOME (EXPENSE)		16,591			20			(165,725	)		141,440			(7,674	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(137,909	)		18			(170,388	)		141,944			(166,335	)
Income Tax (Expense) Benefit		178			—			(178	)		—			—
INCOME (LOSS) FROM CONTINUING OPERATIONS		(137,731	)		18			(170,566	)		141,944			(166,335	)
Income (Loss) From Discontinued Operations, Net of Income Tax		(5,498	)		4,765			—			(1,252	)		(1,985	)
NET INCOME (LOSS)		(143,229	)		4,783			(170,566	)		140,692			(168,320	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			2,246			—			—			2,246
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(143,229	)	$	2,537		$	(170,566	)	$	140,692		$	(170,566	)
Preferred Stock Dividends		—			—			(4,830	)		—			(4,830)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(143,229	)	$	2,537		$	(175,396	)	$	140,692		$	(175,396	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(143,229	)	$	4,783		$	(170,566	)	$	140,692		$	(168,320	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		411			—			—			—			411
Non-Cash Expenses (Income)		(92	)		100			5,876			—			5,884
Depreciation, Depletion, Amortization and Accretion		56,057			3,061			—			(3,378	)		55,740
Gain (Loss) on Derivatives		(17,054	)		—			216			—			(16,838	)
Cash Settlements of Derivatives		24,117			—			903			—			25,020
Dry Hole Expense		198			96			—			(5	)		289
Gain on Sale of Asset		(235	)		(42	)		—			—			(277	)
Impairment Expense		124,856			11			—			—			124,867
Changes in operating assets and liabilities
Accounts Receivable		18,987			(1,707	)		328			(657	)		16,951
Inventory, Prepaid Expenses and Other Assets		1,376			(278	)		(74	)		—			1,024
Accounts Payable and Accrued Liabilities		(21,251	)		(2,492	)		(898	)		657			(23,984	)
Other Assets and Liabilities		(915	)		(73	)		27			—			(961	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		43,226			3,459			(164,188	)		137,309			19,806
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		65,125			(3,184	)		76,592			(138,533	)		—
Proceeds from Joint Venture Acreage Management		43			—			—			—			43
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		3,979			554			—			—			4,533
Proceeds from Joint Venture		16,611			—			—			—			16,611
Acquisitions of Undeveloped Acreage		(21,109	)		(5	)		—			—			(21,114	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(119,054	)		(7,815	)		—			1,224			(125,645	)
NET CASH USED IN INVESTING ACTIVITIES		(54,405	)		(10,450	)		76,592			(137,309	)		(125,572	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			33,960			124,000			—			157,960
Repayments of Long-Term Debt and Lines of Credit		—			(25,443	)		(31,000	)		—			(56,443	)
Repayments of Loans and Other Long-Term Debt		(633	)		(520	)		—			—			(1,153	)
Debt Issuance Costs		—			(3	)		(569	)		—			(572	)
Dividends Paid		—			—			(4,830	)		—			(4,830	)
Distributions by the Partners of Consolidated Subsidiaries		—			(830	)		—			—			(830	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(633	)		7,164			87,601			—			94,132
NET INCREASE (DECREASE) IN CASH		(11,812	)		173			5			—			(11,634	)
CASH – BEGINNING		17,978			118			—			—			18,096
CASH - ENDING	$	6,166		$	291		$	5		$	—		$	6,462

During July 2016, we completed a privately negotiated exchanges of shares of our common stock for outstanding New Notes. In total, we exchanged $43.5 million of our New Notes for approximately 16.8 million shares of our common stock. The shares of our common stock were issued in reliance on the exemption provided in Section 3(a)(9) of the Securities Act of 1933, as amended.

Effective as of July 1, 2016, we entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Amended and Restated Credit Agreement dated as of March 27, 2013 (as amended, modified or supplemented, the “Credit Agreement”) among us; each of the guarantors; Royal Bank of Canada, as administrative agent for the lenders; and the other lenders signatory thereto. The Eleventh Amendment amends certain provisions of the Credit Agreement to, among other things, (i) re-affirm our current borrowing base level of $190.0 million, and provide that there will be no further adjustment to the borrowing base upon the completion of the anticipated sale of assets in the Illinois Basin; (ii) provide flexibility with respect to our use of proceeds from the anticipated sale of assets in the Illinois Basin; (iii) waive our compliance with the current ratio test in the Credit Agreement for the fiscal quarter ending June 30, 2016, and revise the future calculation method for the current ratio to address timing and inclusion of certain reimbursements from joint development partners; and (iv) add a new PDP coverage ratio with a minimum coverage of 1.65 to 1.00. The PDP coverage ratio will be calculated as of the last day of each fiscal quarter, effective with the quarter ending September 30, 2016. For additional information regarding our Senior Credit Facility, see Note 7, Long-Term Debt, to our Consolidated Financial Statements.

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, 2015 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.

We are an independent oil and gas company operating in the Appalachian Basin, where we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. 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, with a regional office in Cranberry, Pennsylvania.

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 (“E&P”) and field services. In June 2016, we entered into a purchase and sale agreement to divest all Illinois Basin components of our E&P operations. As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale”, and as of June 30, 2016, the assets and operations of the Illinois Basin are reported as Discontinued Operations. 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. The sale of Water Solutions closed in July 2015, and we received approximately $66.8 million in proceeds for our 60% interest, net of customary selling expenses. The assets and operating results of Water Solutions are reported as discontinued operations. Unless otherwise noted, information presented in management’s discussion and analysis are for continuing operations.

During the three and six months ended June 30, 2016, we produced 18,116 MMcfe and 35,367 MMcfe, respectively. Overall, our production for the three and six months ended June 30, 2016 averaged 199 MMcfe per day and 194 MMcfe per day, respectively. As of June 30, 2016, we had eight gross (3.5 net) wells drilled and awaiting completion and four gross (2.0 net) wells resting or awaiting pipeline connection. Our drilling and completion activity for the period indicated is set forth in the table below.

Three Months Ended June 30, 2016

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

8.0

3.5

4.0

1.4

3.0

1.1

Three Months Ended June 30, 2015

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

5.0

3.5

8.0

4.0

2.1

Six Months Ended June 30, 2016

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

10.0

4.2

9.0

4.4

19.0

9.1

Six Months Ended June 30, 2015

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

18.0

10.7

15.0

6.8

17.0

10.2

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 natural gas during the three and six months ended June 30, 2016, averaged approximately $1.42 per Mcf and $1.39 per Mcf, respectively, as compared to $1.77 per Mcf and $2.11 per Mcf for the same periods in 2015, respectively. Our realized price, before derivative settlements, for condensate during the three and six months ended June 30, 2016, averaged approximately $37.20 per barrel and $31.91 per barrel, respectively, as compared to $41.37 per barrel and $36.27 per barrel for the same periods in 2015. Our realized price, before derivative settlements, for C3+ NGLs during the three and six months ended June 30, 2016, averaged approximately $15.49 per barrel and $13.87 per barrel, respectively, as compared to $13.92 per barrel and $18.45 per barrel for the same periods in 2015. Our realized price, before derivative settlements, for ethane during the three and six months ended June 30, 2016, averaged approximately $7.49 per barrel and $6.84 per barrel, respectively, as compared to $6.39 per barrel and $6.46 per barrel for the same periods in 2015.

For the three and six months ended June 30, 2016, we recorded impairment expense of approximately $25.1 million and $35.8 million, respectively. Further decreases in commodity prices will decrease our natural gas, condensate and NGL revenues and could reduce the amount of natural gas, condensate and NGL 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 June 30, 2016, approximately 78.6% of our evaluated oil and natural gas properties were located in our Butler Marcellus operating area. Based on estimates of future cash flows, substantial further 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 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 properties totaled approximately $123.4 million as June 30, 2016.

principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. See Note 9, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.7 million aggregate principal amount of New Notes and (ii) issued 8.4 million Shares. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept the Shares. In addition, upon closing we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum payable in cash thereafter. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $0.5 million and $9.0 million in third-party debt issuance costs, in the three and six-month periods ending June 30, 2016, respectively. These costs were recorded as Debt Exchange Expense in Statement of Operations for the three and six-month periods ended June 30, 2016.

During the second quarter of 2016, we entered into privately negotiated debt-to-equity exchanges with certain holders of our Existing Notes as well as holders of our New Notes in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of $26.9 million of our Existing Notes, and $2.2 million of our New Notes, in exchange for the issuance of a total of approximately 5.2 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the company of approximately $23.7 million, presented as Gain on Extinguishment of Debt in our Consolidated Statement of Operations for the three and six month periods ending June 30, 2016.

During the six months ended June 30, 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 9.0 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. These exchanges are recorded within equity, and do not affect our Net Loss from Continuing Operations for the three and six-month periods ending June 30, 2016. See Note 13, Earnings Per Common Share, to our Consolidated Financial Statements, for additional information regarding the effect of the preferred stock conversions on Net Income (Loss) Attributable to Common Shareholders.

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP will participate and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been placed in service and paid for by BSP. The remaining four wells are expected to be placed in service and paid for by BSP during the fourth quarter of 2016. BSP will also fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been placed in sales and for which final payment from BSP is expected during the third quarter of 2016. BSP also has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. During second quarter 2016, BSP exercised their option to participate in 16 of these additional wells, including four that were already drilled. We expect total consideration for this transaction to be $175.0 million with approximately $110.0 million committed as of June 30, 2016. BSP has paid approximately $24.6 million for their interest in elected wells as of June 30, 2016. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of June 30, 2016, 18 of the 38 elected wells were in line and producing, seven wells were drilled and awaiting completion and four wells were awaiting pipeline connection.

On May 20, 2016, we entered into a Purchase and Sale Agreement (“PSA”,) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $51,000. Included in the sale are approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016, due to the elimination of our future abandonment liability associated with wells and pipelines sold to DOG. The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale.

Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).

The following table sets forth summary information regarding NGL, condensate and natural gas production and product prices for the three and six months June 30, 2016 and 2015.

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2016		2015		2016		2015
Production:
Natural Gas (Mcf)		11,327,101		11,926,165		22,631,620		23,429,082
Condensate (Bbls)		90,565		124,381		153,628		259,738
C3+ NGLs (Bbls)		507,990		551,899		997,744		1,073,102
Ethane (Bbls)		532,928		290,453		971,140		479,608
Total (Mcfe)(a)		18,115,999		17,726,563		35,366,692		34,303,770
Average daily production:
Natural Gas (Mcf)		124,474		131,057		124,350		129,442
Condensate (Bbls)		995		1,367		844		1,435
C3+ NGLs (Bbls)		5,582		6,065		5,482		5,929
Ethane (Bbls)		5,856		3,192		5,336		2,650
Total (Mcfe)(a)		199,077		194,801		194,322		189,526
Average sales price(b):
Natural Gas (Mcf)	$	1.42	$	1.77	$	1.39	$	2.11
Condensate (Bbls)	$	37.20	$	41.37	$	31.91	$	36.27
C3+ NGLs (per Bbl)	$	15.49	$	13.92	$	13.87	$	18.45
Ethane (per Bbl)	$	7.49	$	6.39	$	6.84	$	6.46
Total (per Mcfe)(a)	$	1.73	$	2.02	$	1.61	$	2.38
Average NYMEX prices(c):
Oil (per Bbl)	$	45.59	$	57.94	$	39.52	$	53.29
Natural Gas (per Mcf)	$	2.24	$	2.74	$	2.12	$	2.78

The following table sets forth summary information regarding NGL, condensate and natural gas revenues, production volumes, average product prices and average production costs for the three and six months ended June 30, 2016 and 2015.

	Production and Revenue by Product
	For Three Months Ended June 30,				For Six Months Ended June 30,
	2016		2015		2016		2015
Revenue – Natural Gas(a)	$	16,044,170	$	21,087,139	$	31,559,846	$	49,373,044
Volumes (Mcf)		11,327,101		11,926,165		22,631,620		23,429,082
Average Price	$	1.42	$	1.77	$	1.39	$	2.11
Revenue – Condensate (a)	$	3,368,581	$	5,146,483	$	4,902,336	$	9,420,515
Volumes (Bbl)		90,565		124,381		153,628		259,738
Average Price	$	37.20	$	41.37	$	31.91	$	36.27
Revenue – C3+ NGLs(a)	$	7,867,132	$	7,684,203	$	13,842,338	$	19,803,389
Volumes (Bbl)		507,990		551,899		997,744		1,073,102
Average Price	$	15.49	$	13.92	$	13.87	$	18.45
Revenue – Ethane(a)	$	3,990,742	$	1,854,616	$	6,639,427	$	3,099,203
Volumes (Bbl)		532,928		290,453		971,140		479,608
Average Price	$	7.49	$	6.39	$	6.84	$	6.46
Average Production Cost per Mcfe(b)	$	1.38	$	1.35	$	1.39	$	1.37

Operating revenue for the three and six months ended June 30, 2016 decreased 12.6% and 30.3% when compared to the same periods in 2015, respectively. The decrease in operating revenue for the three and six months ended June 30, 2016, can be primarily attributed to lower commodity prices, partially offset by higher production volumes. Our production grew to 18,116 MMcfe for the three-month period ended June 30, 2016, from 17,727 MMcfe for the three-month period ended June 30, 2015, or approximately 2.2%. For the six months ended June 30, 2016, our production increased 3.1% to 35,367 MMcfe from the same period in 2015. For the three month period ended June 30, 2016, our realized sales price for natural gas decreased to $1.42 per Mcf from $1.77 per Mcf, condensate decreased to $37.20 per barrel from $41.37 per barrel, C3+ NGLs increased to $15.49 per barrel from $13.92 per barrel, and ethane increased to $7.49 per barrel from $6.39 per barrel, respectively, when compared to the same period in 2015. For the six month period ended June 30, 2016, our realized sales price for natural gas decreased to $1.39 per Mcf from $2.11 per Mcf, condensate decreased to $31.91 per barrel from $36.27 per barrel, C3+ NGLs decreased to $13.87 per barrel from $18.45 per barrel, and ethane increased to $6.84 per barrel from $6.46 per barrel, respectively, when compared to the same period in 2015.

Operating expenses decreased $107.4 million and $115.1 million for the three and six months ended June 30, 2016, as compared to the same periods in 2015, 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 decreases in operating expenses were largely attributable to fewer impairment charges, reduced DD&A expense, and gains realized on the disposal of assets. The decrease of many of these operating expenses is consistent with the overall decrease in activity within the industry in conjunction with a decrease in the cost of goods and services and other cost control measures that we have implemented. The decrease in impairment was largely indicative of the increase in commodity prices as compared to March 31, 2016.

Comparison of the Three Months Ended June 30, 2016 to the Three Months Ended June 30, 2015

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the three-month periods ended June 30, 2016 and 2015 is summarized in the following table:

	For Three Months Ended June 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2016		2015		Change			%
Gas sales revenue	$	16,044	$	21,087	$	(5,043	)		(23.9	)%
Gas derivatives realized(a)(b)	$	14,857	$	9,067	$	5,790			63.9	%
Total gas revenue and derivatives realized	$	30,901	$	30,154	$	747			2.5	%
Condensate sales revenue	$	3,369	$	5,146	$	(1,777	)		(34.5	)%
Oil and condensate derivatives realized(a)	$	310	$	2,368	$	(2,058	)		(86.9	)%
Total condensate revenue and derivatives realized	$	3,679	$	7,514	$	(3,835	)		(51.0	)%
C3+ NGL revenue	$	7,867	$	7,684	$	183			2.4	%
C3+ NGL derivatives realized(a)(c)	$	2,255	$	2,036	$	219			10.8	%
Total C3+ NGL revenue	$	10,122	$	9,720	$	402			4.1	%
Ethane revenue	$	3,991	$	1,855	$	2,136			115.1	%
Ethane derivatives realized(a)	$	—	$	67	$	(67	)		(100.0	)%
Total Ethane revenue	$	3,991	$	1,922	$	2,069			107.6	%
Consolidated sales	$	31,271	$	35,772	$	(4,501	)		(12.6	)%
Consolidated derivatives realized(a)	$	17,422	$	13,538	$	3,884			28.7	%
Total NGL, condensate and gas revenue and derivatives realized	$	48,693	$	49,310	$	(617	)		(1.3	)%
Total Mcfe Production		18,115,999		17,726,563		389,436			2.2	%
Average Realized Price per Mcfe	$	2.69	$	2.78	$	(0.09	)		(3.2	)%

Average realized price received for natural gas, condensate and NGLs during the second quarter of 2016, after the effect of derivative activities, was $2.69 per Mcfe, a decrease of 3.2%, or $0.09 per Mcfe, from the same period in 2015. 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, increased 7.9%, or $0.20 per Mcf, to $2.73 per Mcf. The average price for condensate, after the effect of derivative activities, decreased 32.8%, or $19.79 per barrel, to $40.62 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 13.1%, or $2.31 per barrel, to $19.93 per barrel. The average price for ethane, after the effect of derivative activities, increased 13.2% or $0.87 per barrel, to $7.49 per barrel. Our derivative activities effectively increased net realized prices by $0.96 per Mcfe in the second quarter of 2016 and $0.76 per Mcfe in the second quarter of 2015. During the second quarter of 2016, we liquidated a number of NGL and natural gas derivative positions which resulted in approximately $2.2 million of additional proceeds during the quarter. Excluding the effect of these liquidations, realized prices for natural gas and C3+ NGLs would have been approximately $2.37 per Mcf and $21.89 per barrel, respectively.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.82 per Mcf during the second quarter of 2016 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. 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 second quarter of 2016 increased 2.2% or 389.4 Mcfe from the first quarter of 2015 primarily due to success of our Marcellus and Utica Shale horizontal drilling activities. Natural gas production decreased approximately 5.0%, condensate production decreased approximately 27.2%, C3+ NGL production decreased approximately 8.0% and our ethane production increased approximately 83.5%. Reductions in natural gas production volumes are related to the increase in ethane production volumes, as the amount of ethane extraction from produced natural gas is controlled at the processing plant. The product blend is optimized for pricing and demand conditions.

Overall, our production for the second quarter of 2016 averaged 199,077 Mcfe per day, of which 62.5% was attributable to natural gas, 3.0% to condensate, 16.8% to C3+ NGLs and 17.7% was a result of ethane production.

Statements of Operations for the three-month periods ended June 30, 2016 and 2015 are as follows:

	For the Three Months Ended June 30,
($ in Thousands)	2016			2015			Change			%
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	31,271		$	35,772		$	(4,501	)		(12.6	)%
Other Revenue (Expense)		(6	)		12			(18	)		(150.0	)%
TOTAL OPERATING REVENUE		31,265			35,784			(4,519	)		(12.6	)%
OPERATING EXPENSES
Production and Lease Operating Expense		25,221			24,270			951			3.9	%
General and Administrative Expense		4,837			7,394			(2,557	)		(34.6	)%
Gain on Disposal of Asset		(4,307	)		(373	)		(3,934	)		1,054.7	%
Impairment Expense		25,139			117,839			(92,700	)		(78.7	)%
Exploration Expense		803			755			48			6.4	%
Depreciation, Depletion, Amortization and Accretion		14,750			24,698			(9,948	)		(40.3	)%
Other Operating (Income) Expense		704			(66	)		770			(1,166.7	)%
TOTAL OPERATING EXPENSES		67,147			174,517			(107,370	)		(61.5	)%
LOSS FROM OPERATIONS		(35,882	)		(138,733	)		102,851			(74.1	)%
OTHER EXPENSE
Interest Expense		(11,439	)		(12,181	)		742			(6.1	)%
Loss on Derivatives, Net		(29,169	)		(281	)		(28,888	)		10,280.4	%
Other Income		12			61			(49	)		(80.3	)%
Debt Exchange Expense		(533	)		—			(533	)		100.0	%
Gain on Extinguishment of Debt		23,707			—			23,707			100.0	%
Loss on Equity Method Investments		—			(208	)		208			(100.0	)%
TOTAL OTHER EXPENSE		(17,422	)		(12,609	)		(4,813	)		38.2	%
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(53,304	)		(151,342	)		98,038			(64.8	)%
Income Tax Benefit		393			—			—			100.0%
LOSS FROM CONTINUING OPERATIONS		(52,911	)		(151,342	)		98,431			(65.0	)%
Income From Discontinued Operations, Net of Income Taxes		(1,683	)		(461	)		(1,222	)		265.1	%
NET LOSS		(54,594	)		(151,803	)		97,209			(64.0	)%
Net Income Attributable to Noncontrolling Interests		—			949			(949	)		(100.0	)%
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(54,594	)	$	(152,752	)	$	98,158			(64.3	)%

Production and Lease Operating Expense increased approximately $1.0 million, or 3.9%, in the second quarter of 2016 from the same period in 2015. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells 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 86.5% of our total Production and Lease Operating Expense in the second quarter of 2016, as compared to 84.6% from the same period in 2015. 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 increased to $1.39 per Mcfe in the three months ended June 30, 2016 from $1.37 per Mcfe in the same period in 2015.

Gain on Disposal of Assets was $4.3 million for the second quarter 2016. A gain of approximately $4.6 million was generated during the quarter by elimination of our future abandonment liability associated with the sale of our operated conventional wells and pipelines, partially offset by approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale. Approximately $0.1 million of loss on disposal was generated by the sale of vehicles and office equipment during the quarter. Gains from the disposal of assets in the second quarter of 2015 were negligible.

G&A Expense for the second quarter of 2016 decreased approximately $2.6 million, or 34.6%, to $4.8 million from the same period in 2015. We have undertaken several cost control measures during the second three months of 2016, 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 second quarter of 2016 was approximately $25.1 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 second quarter of 2016 included $24.2 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior County, Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. Impairment of proved properties in our Butler County operations totaled approximately $0.8 million during the second quarter of 2016. The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of June 30, 2016, 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, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the second quarter of 2016 was approximately $0.8 million, as compared to $0.8 million for same period in 2015. The expense incurred in 2016 was due to geological and geophysical type expenditures. Approximately $0.1 million of the expense incurred in 2015 was due to geological and geophysical type expenditures, $0.5 million was due to payment of delay rentals, and $0.2 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. 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 second quarter of 2016 decreased approximately $9.9 million, or 40.3%, from $24.7 million for the same period in 2015. Contributing to the decrease in DD&A expense were lower second quarter depreciable asset values from the impact of 2015 impairments, partially offset by lower year end reserves, which were triggered by the ongoing lower commodity pricing environment and the related effect on our estimated proved reserves, when compared to the same period in 2015.

Interest Expense for the second quarter of 2016 was approximately $11.4 million as compared to $12.2 million for the same period in 2015. The decrease in interest expense is primarily due to reduced bond interest expense as a result of the Senior Notes exchange completed on March 31, 2016. The decrease is partially offset by increased amortization of bond costs as a result of the Senior Notes exchange, and increased interest expense due to increased borrowing on our revolving credit facility. We discuss our senior notes and revolving credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain (Loss) on Derivatives, net included a loss of approximately $29.2 million for the second quarter of 2016 as compared to a loss of $0.3 million for the same period in 2015. The loss recorded for the second quarter of 2016 included cash receipts for commodity derivatives of $17.3 million while the loss incurred in the second quarter of 2015 included cash receipts of approximately $13.9 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 2016 and 2017, 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.

Debt Exchange Expense for the second quarter of 2016 totaled approximately $0.5 million. These charges relate to our Existing Notes for New Notes exchange, completed on March 31, 2016. We accounted for the exchange as a troubled debt restructuring, which mandates that current third-party expenses be charged against income in the current period.

Gain on Extinguishment of Debt for the second quarter of 2016 totaled approximately $23.7 million. The gain resulted from debt to equity exchanges under troubled debt restructuring rules with certain holders of our Senior Notes, wherein approximately $29.1 million of outstanding Senior Notes were reacquired by the company in exchange for approximately 5.2 million shares of our common stock. We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Benefit was approximately $0.4 million for the second quarter of 2016. There was no tax expense or benefit for the second quarter of 2015 attributed to continuing operations, due the recording of a full valuation allowance against net deferred tax assets at June 30, 2015. A full valuation allowance has been recorded against net deferred tax assets at June 30, 2016. The tax benefit recognized in the second quarter of 2016 represents a reduction to the accrual for our estimated Alternative Minimum Tax (“AMT”) liability for 2016. Our effective tax rate for continuing operations during the three months ended June 30, 2016 was approximately 0.7%, as compared to 0% during the comparable period in 2015. Our effective tax rate in the second quarter of 2016 was different than the statutory rate of 35% due to the recording of valuation allowances, and effects of the AMT. As of June 30, 2016, 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. As a result of the Senior Note Exchange completed on March 31, 2016, we generated approximately $543.2 million of taxable Cancellation of Debt Income (“CODI”) income, which is calculated by comparing the fair value of the New Notes and the face value of the Existing Notes exchanged. In the second quarter of 2016, we completed debt to equity exchanges with certain holders of our Senior Notes, resulting in taxable losses and reductions of our current year CODI income of approximately $2.0 million. See Note 7, Long-Term Debt, to our Consolidated Financial Statements, for additional information on our debt for equity exchanges. We expect to offset this income by utilizing our net operating loss carryforwards and through the effect of interest expense amortizations of the Original Issue Discount generated by the Exchange transactions.

Net Loss Attributable to Rex Energy for the second quarter of 2016 was approximately $54.6 million, as compared to a loss of $152.8 million for the same period in 2015 as a result of factors discussed above.

Comparison of the Six Months Ended June 30, 2016 to the Six Months Ended June 30, 2015

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the six-month periods ended June 30, 2016 and 2015 is summarized in the following table:

	For Six Months Ended June 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2016		2015		Change			%
Gas sales revenue	$	31,560	$	49,373	$	(17,813	)		(36.1	)%
Gas derivatives realized(a)(b)	$	23,080	$	14,339	$	8,741			61.0	%
Total gas revenue and derivatives realized	$	54,640	$	63,712	$	(9,072	)		(14.2	)%
Condensate sales revenue	$	4,902	$	9,421	$	(4,519	)		(48.0	)%
Oil and condensate derivatives realized(a)	$	2,098	$	6,113	$	(4,015	)		(65.7	)%
Total condensate revenue and derivatives realized	$	7,000	$	15,534	$	(8,534	)		(54.9	)%
C3+ NGL revenue	$	13,843	$	19,803	$	(5,960	)		(30.1	)%
C3+ NGL derivatives realized(a)(c)	$	5,211	$	3,539	$	1,672			47.2	%
Total C3+ NGL revenue	$	19,054	$	23,342	$	(4,288	)		(18.4	)%
Ethane revenue	$	6,639	$	3,099	$	3,540			114.2	%
Ethane derivatives realized(a)	$	144	$	126	$	18			14.3	%
Total Ethane revenue	$	6,783	$	3,225	$	3,558			110.3	%
Consolidated sales	$	56,944	$	81,696	$	(24,752	)		(30.3	)%
Consolidated derivatives realized(a)	$	30,533	$	24,117	$	6,416			26.6	%
Total NGL, condensate and gas revenue and derivatives realized	$	87,477	$	105,813	$	(18,336	)		(17.3	)%
Total Mcfe Production		35,366,692		34,303,770		1,062,922			3.1	%
Average Realized Price per Mcfe	$	2.47	$	3.08	$	(0.61	)		(19.8	)%

Average realized price received for natural gas, condensate and NGLs during the first half of 2016, after the effect of derivative activities, was $2.47 per Mcfe, a decrease of 19.8%, or $0.61 per Mcfe, from the same period in 2015. 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 11.2%, or $0.31 per Mcf, to $2.41 per Mcf. The average price for condensate, after the effect of derivative activities, decreased 23.8%, or $14.24 per barrel, to $45.56 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, decreased 12.24%, or $2.65 per barrel, to $19.10 per barrel. The average price for ethane, including the effect of derivatives, increased 3.9% or $0.26 per barrel, to $6.98 per barrel. Our derivative activities

effectively increased net realized prices by $0.86 per Mcfe in the first half of 2016 and $0.70 per Mcfe in the first half of 2015. Excluding the effect of derivative liquidations during the second quarter of 2016, realized prices during the first half of 2016 for natural gas and C3+ NGLs would have been approximately $2.24 per mcf and $20.10 per barrel, respectively.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.73 per Mcf during the first half of 2016 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. 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 six months of 2016 increased 3.1% or 1,062.9 Mcfe from the first quarter of 2015 primarily due to success of our Marcellus and Utica Shale horizontal drilling activities. Natural gas production decreased approximately 3.4%, condensate production decreased approximately 40.9%, C3+ NGL production decreased approximately 7.0% and our ethane production increased approximately 102.5%. Reductions in natural gas production volumes are related to the increase in ethane production volumes, as the amount of ethane extraction from produced natural gas is controlled at the processing plant. The product blend is optimized for pricing and demand conditions.

Overall, our production for the first six months of 2016 averaged 194,322 Mcfe per day, of which 64.0% was attributable to natural gas, 2.6% to condensate, 16.9% to C3+ NGLs and 16.5% was a result of ethane production.

Statements of Operations for the six-month periods ended June 30, 2016 and 2015 are as follows:

	For the Six Months Ended June 30,
($ in Thousands)	2016			2015			Change			%
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	56,944		$	81,696		$	(24,752	)		(30.3	)%
Other Revenue		7			22			(15	)		(68.2	)%
TOTAL OPERATING REVENUE		56,951			81,718			(24,767	)		(30.3	)%
OPERATING EXPENSES
Production and Lease Operating Expense		49,672			47,387			2,285			4.8	%
General and Administrative Expense		10,121			15,745			(5,624	)		(35.7	)%
Gain on Disposal of Assets		(4,295	)		(309	)		(3,986	)		1,290.0	%
Impairment Expense		35,780			124,687			(88,907	)		(71.3	)%
Exploration Expense		1,738			1,194			544			45.6	%
Depreciation, Depletion, Amortization and Accretion		31,262			46,537			(15,275	)		(32.8	)%
Other Operating Expense		1,030			5,138			(4,108	)		(80.0	)%
TOTAL OPERATING EXPENSES		125,308			240,379			(115,071	)		(47.9	)%
LOSS FROM OPERATIONS		(68,357	)		(158,661	)		90,304			(56.9	)%
OTHER EXPENSE
Interest Expense		(24,469	)		(24,193	)		(276	)		1.1	%
Gain (Loss) on Derivatives, Net		(25,120	)		16,838			(41,958	)		(249.2	)%
Other Income		12			92			(80	)		(87.0	)%
Debt Exchange Expense		(9,014	)		—			(9,014	)		100.0	%
Gain on Extinguishment of Debt		23,707			—			23,707			100.0	%
Loss on Equity Method Investments		—			(411	)		411			(100.0	)%
TOTAL OTHER EXPENSE		(34,884	)		(7,674	)		(27,210	)		354.6	%
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(103,241	)		(166,335	)		63,094			(37.9	)%
Income Tax Expense		(2,321	)		—			(2,321	)		100.0	%
LOSS FROM CONTINUING OPERATIONS		(105,562	)		(166,335	)		60,773			(36.5	)%
Loss From Discontinued Operations, Net of Income Taxes		(9,173	)		(1,985	)		(7,188	)		362.1	%
NET LOSS		(114,735	)		(168,320	)		53,585			(31.8	)%
Net Income Attributable to Noncontrolling Interests		—			2,246			(2,246	)		(100.0	)%
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(114,735	)	$	(170,566	)	$	55,831			(32.7	)%

Production and Lease Operating Expense increased approximately $2.3 million, or 4.8%, in the first half of 2016 from the same period in 2015. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells 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 87.1% of our total Production and Lease Operating Expense in the first half of 2016, as compared to 83.1% from the same period in 2015. 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 increased to $1.40 per Mcfe in the six months ended June 30, 2016 from $1.34 per Mcfe in the same period in 2015.

Gain on Disposal of Assets was $4.3 million for the first half of 2016. The gain was generated primarily by elimination of our future abandonment liability associated with the sale of our operated conventional gas wells and pipelines. Gains from the disposal of assets in the first half of 2015 were negligible.

G&A Expense for the first half of 2016 decreased approximately $5.6 million, or 35.7%, to $10.1 million from the same period in 2015. We have undertaken several cost control measures during the first three months of 2016, 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. During the first quarter of 2016, the board of directors approved certain performance factors for restricted stock that vested in March 2016. These performance factors resulted in reduced expense due to forfeitures on performance-based restricted stock awards of approximately $1.6 million.

Impairment Expense for the first half of 2016 was approximately $35.8 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 first half of 2016 included $34.9 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. Impairment of proved properties in our Butler County operations totaled approximately $0.9 million during the second quarter of 2016. The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of June 30, 2016, 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, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the first half of 2016 was approximately $1.7 million, as compared to $1.2 million for same period in 2015. Approximately $0.9 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and $0.8 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. Approximately $0.5 million of the expense incurred in 2015 was due to geological and geophysical type expenditures, $0.5 million was due to payment of delay rentals, and $0.2 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. 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 first half of 2016 decreased approximately $15.3 million, or 32.8%, from $46.5 million for the same period in 2015. Contributing to the decrease in DD&A expense were lower first quarter depreciable asset values from the impact of 2015 impairments, partially offset by lower year end reserves, which were triggered by the ongoing lower commodity pricing environment and the related effect on our estimated proved reserves, when compared to the same period in 2015.

Other Operating Expense for the first half of 2016 decreased to approximately $1.0 million from $5.1 million in the first half of 2015. The decrease is the result of termination charges of approximately $4.8 million incurred for the cancellation of drilling rig contracts before expiration of their original term during the first half of 2015. There were no drilling rig termination charges incurred in the first half of 2016.

Interest Expense for the six months ended June 30, 2016 was approximately $24.5 million as compared to $24.2 million for the same period in 2015. The increase in interest expense is primarily due increased amortization of bond costs as a result of the Senior Notes exchange completed on March 31, 2016, and increased interest expense due to increased borrowing on our revolving credit facility. The increase is partially offset by reduced bond interest expense as a result of the Senior Notes exchange. We discuss our senior notes and revolving credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Loss on Derivatives, net included a loss of approximately $25.1 million for the first half of 2016 as compared to a gain of approximately $16.8 million for the same period in 2015. The loss recorded for the first half of 2016 included cash receipts for commodity derivatives of $30.3 million while the gain incurred in the first quarter of 2015 included cash receipts of approximately $25.0 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.

Debt Exchange Expense for the six months ended June 30, 2016 totaled approximately $9.0 million. These charges relate to our exchange of Existing for New Notes completed on March 31, 2016. We accounted for the exchange as a troubled debt restructuring, which mandates that current third-party expenses be charged against income in the current period.

Gain on Extinguishment of Debt for the six months ended June 30, 2016 totaled approximately $23.7 million. The gain resulted from debt to equity exchanges under troubled debt restructuring rules with certain holders of our Senior Notes, wherein approximately $29.1 million of outstanding Senior Notes were reacquired by the company in exchange for approximately 5.2 million shares of our common stock. We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements

Income Tax Expense was approximately $2.3 million for the first half 2016. There was no tax expense or benefit for the first half of 2015 attributed to continuing operations, due the recording of a full valuation allowance against net deferred tax assets at June 30, 2015. A full valuation allowance has been recorded against net deferred tax assets at June 30, 2016. The tax expense recognized in the first half of 2016 represents our estimated Alternative Minimum Tax (“AMT”) liability for the six months ending June 30, 2016. Our effective tax rate for continuing operations during the six months ended June 30, 2016 was approximately -2.2%, as compared to 0% during the comparable period in 2015. Our effective tax rate in the first half of 2016 was different than the statutory rate of 35% due to the recording of valuation allowances, and effects of the AMT. As of June 30, 2016, 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. As a result of the Senior Note Exchange completed on March 31, 2016, we generated approximately $543.2 million of taxable Cancellation of Debt Income (“CODI”) income, which is calculated by comparing the fair value of the New Notes and the face value of the Existing Notes exchanged. In the second quarter of 2016, we completed debt to equity exchanges with certain holders of our Senior Notes, resulting in taxable losses and reductions of our current year CODI income of approximately $2 million. See Note 7, Long-Term Debt, to our Consolidated Financial Statements, for additional information on our debt for equity exchanges. We expect to offset this income by utilizing our net operating loss carryforwards and through the effect of interest expense amortizations of the Original Issue Discount generated by the Exchange transactions.

Net Loss Attributable to Rex Energy for the first half of 2016 was approximately $114.7 million, as compared to a loss of $170.6 million for the same period in 2015 as a result of factors discussed above.

EBITDAX (Non-GAAP) from continuing operations decreased approximately $0.7 million to $19.0 million for the three-month period ended June 30, 2016, as compared to the same period in 2015. EBITDAX from continuing operations decreased approximately $20.5 million to $27.5 million for the six-month period ended June 30, 2016, as compared to the same period in 2015. The decrease in EBITDAX can be primarily attributed to decreased average sales prices for natural gas and NGLs, resulting in decreased operating revenues. The decrease during the three months ended June 30, 2016 was partially offset by the liquidation of certain natural gas and C3+ NGL derivatives, which resulted in approximately $2.2 million of proceeds above what would normally have been received. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

LOE per Mcfe measures the average cost of extracting natural gas, condensate and NGLs from our 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 natural gas and NGL reserves in the ground. LOE per Mcfe increased to $1.39 for the three months ended June 30, 2016, as compared to $1.37 for the same period in 2015. LOE per Mcfe increased to $1.40 for the six months ended June 30, 2016, as compared to $1.38 for the same period in 2015. Our LOE is largely comprised of variable type costs such as transportation, marketing, processing and gathering. For the second quarter of 2016, transportation, capacity and processing fees accounted for approximately 86.5% of our total Production and Lease Operating Expense as compared to 84.6% during the same period of 2015. For the six months ended June 30, 2016, transportation, capacity and processing fees accounted for approximately 87.1% of our total Production and Lease Operating Expense as compared to 83.1% during the same period of 2015. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Various agreements that we have entered include firm capacity rights, for which we may incur a fee for unused capacity. As we continue to grow our operations, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

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 $0.27 for the three-month period ended June 30, 2016, as compared to $0.42 for the same period in 2015. During the first half of 2016, G&A per Mcfe decreased to $0.29 as compared to $0.46 for the same period in 2015. The decreases are predominately due to further cost control measures and headcount reductions implemented during the first half 2016 in response to our decreased capital plan related to commodity price declines combined with our increase in production.

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the six months ended June 30, 2016, we spent $24.2 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage. We expect to be reimbursed by joint venture partners for approximately $11.0 million for costs incurred during the second quarter of 2016 that were not billed until the third quarter. We funded our capital program with proceeds from our Senior Credit Facility, cash from operations and funds received from the closing of the BSP joint development agreement. The remainder of our 2016 capital budget is expected to be funded primarily by cash on hand, cash flows from operations, and potential future asset sales and joint ventures.

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 changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, cash flows from operations, borrowings from our revolving credit facility and net proceeds from debt and equity offerings have been primarily used to fund exploration and development of our oil and gas interests. As of June 30, 2016, we had approximately $3.4 million of cash on hand and outstanding borrowings under our $190.0 million revolving credit facility of approximately $146.7 million with an additional $43.3 million of undrawn letters of credit outstanding. The next borrowing base redetermination will occur on or about October 1, 2016. In May 2016, a third-party midstream provider drew on an outstanding letter of credit in the amount of $3.9 million related to an ongoing gas transportation project for which we declined to provide additional collateral. Both parties intend to honor the original transportation agreement and the terms within that agreement.

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 acquisitions and our development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under our revolving credit facility. At June 30, 2016, we were in compliance with all required debt covenants under our revolving credit facility, with the exception of our minimum current ratio requirement of 1.0 to 1.0. Due to changes in our drilling schedule and the timing of reimbursements from our joint venture partners we did not meet our minimum current ratio requirement, for which we received a waiver from the lenders for the period ended June 30, 2016. Subsequent to June 30, 2016, we expect this ratio to improve and do not expect to incur any covenant violations.

Due to the current depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. As a result of not declaring the first quarter dividend on our Series A Preferred Stock, we are no longer eligible to use Form S-3 registration statements. Until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register securities with the SEC (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital. We may need to take additional actions in the future to address current industry trends and maintain our ability to pay expenses and service our indebtedness, including, but not limited to, selling assets or raising capital by issuing additional debt or equity securities.

We have Existing Notes and New Notes (together, the “Senior Notes”) that 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 to 1.00. As of June 30, 2016, our Fixed Charge Coverage Ratio was 1.16 to 1.00. We expect our Fixed Charge Coverage Ratio to improve in 2016 based on our projections of decreased interest expense related to our Senior Notes. As of June 30, 2016, we were limited to incurring an additional $148.6 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding notes to be due and payable immediately.

We are not restricted as to our borrowings under our revolving credit facility; however we are subject to the minimum financial requirements detailed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties. In addition, our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million, with any excess to be used to pay down the outstanding Senior Credit Facility balance; however we retain the right to draw on the revolving credit facility so long as there are amounts available under our borrowing base.

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 $199.8 million over the next five years, depending on our levels of production. In connection with 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 $414.0 million over the life of the agreements. These guarantees will decrease over time as the commitments are satisfied.

Our revolving credit facility contains a number of restrictive covenants and limitations that will impose significant operating and financial restrictions on us. In particular, our financial covenants require us to maintain a minimum consolidated current ratio of 1.0 to 1.0 and a maximum ratio of net senior-secured debt to EBITDAX, a non-GAAP measure, of 2.75 to 1.0. Failure to comply with these covenants could have an adverse effect on our business. If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:

In order to improve our liquidity positions to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, including (i) debt-for-debt or debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing capital expenditures, (iv) improving cash flows from operations, (v) effectively managing working capital, (vi) adding hedging positions, (vii) asset sales and (viii) and in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations.

Financial Condition and Cash Flows for the Six Months Ended June 30, 2016 and 2015

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

Net cash provided by (used in) operating activities decreased from cash provided by operating activities of $19.8 million in the first half of 2015 to cash used of $4.6 million for the same period in 2016. This was primarily due to a reduction in oil, natural gas and NGL prices and approximately $9.0 million of Debt Exchange Expense. These decreases in cash flow were partially offset by increases in production in our Appalachian Basin operations and a decrease in G&A and Other Operating Expenses.

Net cash used in investing activities decreased by approximately $101.6 million from the first half of 2016 to $24.0 million as compared to the same period in 2015. This change is primarily attributed to lower activity levels related to the currently depressed commodity price environment and $24.6 million received from our joint venture with BSP in 2016 compared with the $130.1 million of capital activity during the first half of 2015.

Net cash provided by financing activities decreased by approximately $63.2 million for the first half of 2016 to $31.0 million from $94.1 million over the same period in 2015. The decrease in cash provided is primarily due to lower net borrowings on our revolving credit facility and dividends paid during the first half of 2015.

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.

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.

During the quarter ended June 30, 2016, 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, 2015. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 5, “Recently Issued Accounting Pronouncements.”

“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:

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

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

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A 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 June 30,						Six Months Ended June 30,
($ in Thousands)	2016			2015			2016			2015
Net Loss From Continuing Operations	$	(52,911	)	$	(151,342	)	$	(105,562	)	$	(166,335	)
Add Back (Less) Non-Recurring Costs (Income)¹		(23,174	)		(248	)		(14,694	)		4,774
Add Back Depletion, Depreciation, Amortization and Accretion		14,750			24,698			31,262			46,537
Add Back Non-Cash Compensation Expense		1,164			1,804			1,016			4,635
Add Back Interest Expense		11,439			12,181			24,469			24,193
Add Back Impairment Expense		25,139			117,839			35,780			124,687
Add Back Exploration Expenses		803			755			1,738			1,194
Less Gain on Disposal of Assets		(4,307	)		(373	)		(4,295	)		(309	)
Add Back (Less) (Gain) Loss on Financial Derivatives		29,169			281			25,120			(16,838	)
Add Back Cash Settlement of Derivatives²		17,345			13,941			30,340			25,020
Add Back (Less) Income Tax Expense (Benefit)		(393	)		—			2,321			—
Add Back Non-Cash Portion of Equity Method Investments		—			203			—			406
EBITDAX From Continuing Operations	$	19,024		$	19,739		$	27,495		$	47,964
Net Loss From Discontinued Operations, Net of Income Taxes	$	(1,683	)	$	(461	)	$	(9,173	)	$	(1,985	)
Income Attributable to Noncontrolling Interests		—			(949	)		—			(2,246	)
Loss From Discontinued Operations Attributable to Rex Energy		(1,683	)		(1,410	)		(9,173	)		(4,231	)
Add Back Depletion, Depreciation, Amortization and Accretion		2,186			4,877			5,083			9,203
Add Back Non-Cash Compensation Expense		139			154			259			286
Add Back Interest Expense		1			253			3			448
Add Back Impairment Expense		—			3			3,543			178
Add Back Exploration Expenses		85			162			143			241
Add Back (Less) (Gain) Loss on Disposal of Assets		(2	)		62			(43	)		31
Less Non-Cash Portion of Noncontrolling Interests		—			(107	)		—			(186	)
Add Back (Less) Income Tax Expense (Benefit)		120			(101	)		(502	)		242
Add EBITDAX From Discontinued Operations	$	846		$	3,893		$	(687	)	$	6,212
EBITDAX (Non-GAAP)	$	19,870		$	23,632		$	26,808		$	54,176

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

For the three and six months ended June 30, 2016, we received net settlements on oil, NGL and natural gas derivatives of approximately $17.4 million and $30.5 million, respectively, as compared to receiving net settlements of approximately $13.5 million and $24.1 million for the three and six months ended June 30, 2015, respectively. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of June 30, 2016, we had approximately 100.0% of our annualized condensate production hedged through the remainder of 2016, over 100.0% and 50.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 50.0% of our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our Illinois Basin production and 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 natural gas, condensate and NGL 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 six months ended June 30, 2016, our average realized prices for natural gas was lower than the average NYMEX prices over the same period by approximately $0.82 per Mcf and $0.73 per Mcf. 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 11,113 MMcf at an average differential to Henry Hub NYMEX of $0.88 per Mcf for the remainder of 2016 in addition to basis swaps for 19,150 MMcf at an average differential to Henry Hub NYMEX of $0.30 per Mcf for 2017. For the three and six months ended June 30, 2016, we paid cash settlements on our basis differential derivatives of approximately $1.4 million and $1.7 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 June 30, 2016, refer to Part I, Item 1. Financial Statements - Note 8, “Derivative Instruments and Fair Value Measurements”.

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, 2015, 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.

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

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, NGLs and natural gas. Conversely, increases in the market prices for oil, NGLs and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on production through June 30, 2016, we project that a 10% decline in the price per barrel of oil and NGLs and the price per Mcf of gas from the first six months of 2016 average would reduce our gross revenues, before the effects of derivatives, for the remaining six months of 2016 by approximately $3.1 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.

At June 30, 2016, we had the following commodity derivative contracts outstanding:

Period	Volume	Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2016 - Collars	272,000 Bbls	$	—	$	38.05	$	49.15	$	—		$	(956	)
2016 - Three-Way Collars	150,000 Bbls		31.20		41.40		49.60		—			(442	)
2016 - Cap Swaps	60,000 Bbls		30.00		—		—		44.00			(361	)
	482,000 Bbls										$	(1,759	)
Natural Gas
2016 - Swaps	8,155,000 Mcf		—		—		—		2.54		$	(3,475	)
2016 - Swaptions	600,000 Mcf		—		—		—		3.15			79
2016 - Cap Swaps	2,400,000 Mcf		2.59		—		—		3.07			(612	)
2016 - Collars	2,110,000 Mcf		—		2.63		3.03		—			(409	)
2016 - Three-Way Collars	1,505,000 Mcf		2.11		2.68		3.30		—			(377	)
2016 - Put Spreads	6,015,000 Mcf		2.51		3.27		—		—			760
2016 - Basis Swaps - Dominion South	11,113,000 Mcf		—		—		—		(0.88	)		(139	)
2017 - Swaps	2,460,000 Mcf		—		—		—		3.21			178
2017 - Swaptions	0 Mcf		—		—		—		—			(670	)
2017 - Cap Swaps	3,900,000 Mcf		2.35		—		—		2.81			(1,559	)
2017 - Three-Way Collars	16,900,000 Mcf		2.32		3.01		3.87		—			594
2017 - Calls	3,000,000 Mcf		—		—		3.64		—			(1,277	)
2017 - Collars	1,400,000 Mcf		—		2.40		3.10		—			(348	)
2017 - Basis Swaps - Dominion South	4,550,000 Mcf		—		—		—		(0.83	)		(1,073	)
2017 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(372	)
2018 - Swaps	960,000 Mcf		—		—		—		3.25			495
2018 - Swaptions	0 Mcf		—		—		—		—			(320	)
2018 - Three-Way Collars	7,875,000 Mcf		2.29		2.88		3.56		—			(755	)
2018 - Calls	5,810,000 Mcf		—		—		3.97		—			(485	)
2018 - Basis Swaps - Dominion South	6,400,000 Mcf		—		—		—		(0.83	)		(1,073	)
2018 - Basis Swaps - Texas Gas	14,600,000 Mcf		—		—		—		(0.13	)		(372	)
2019 - Basis Swaps - Dominion South	7,300,000 Mcf		—		—		—		(0.83	)		(1,073	)
2020 - Basis Swaps - Dominion South	7,320,000 Mcf		—		—		—		(0.83	)		(1,073	)
	128,973,000 Mcf										$	(13,356	)
NGLs
2016 - C3+ NGL Swaps	714,000 Bbls		—		—		—		26.04		$	(261	)
2016 - Ethane Swaps	330,000 Bbls		—		—		—		8.40			(766	)
2017 - C3+ NGL Swaps	468,000 Bbls		—		—		—		20.16			(2,228	)
2017 - Ethane Swaps	540,000 Bbls		—		—		—		10.08			(1,220	)
	2,052,000 Bbls										$	(4,475	)
Refined Product (Heating Oil)
2016 - Swaps	6,000 Bbls	$	—	$	—	$	—	$	84.00		$	(117	)
	6,000 Bbls										$	(117	)

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 June30, 2016, 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, 2015. Based on our total debt as of June 30, 2016 of approximately $793.3 million, a 1.0% change in interest rates would impact our interest expense by approximately $7.9 million.

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, summarized and reported within the time periods specified in SEC rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), to allow timely decisions regarding required disclosure.

Our management (with the participation of our CEO and CFO) has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our CEO and CFO have concluded that, as of June 30, 2016, 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.

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended June 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

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.

During the quarter ended June 30, 2016, 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, 2015.

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.

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.

Large Accelerated filer	¨	Accelerated filer	x

Non-accelerated filer	¨	Smaller Reporting Company	¨

			PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	4
		Consolidated Balance Sheets As of June 30, 2016 (Unaudited) and December 31, 2015	4
		Consolidated Statements of Operations (Unaudited) for the three and six-month periods ended June 30, 2016 and June 30, 2015	5
		Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the six-month period ended June 30, 2016	6
		Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2016 and June 30, 2015	7
		Notes to Consolidated Financial Statements (Unaudited)	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	39
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	56
	Item 4.	Controls and Procedures	57
PART II. OTHER INFORMATION			58
	Item 1.	Legal Proceedings	58
	Item 1A.	Risk Factors	58
	Item 6.	Exhibits	58
SIGNATURES			59
EXHIBIT INDEX			60

($ in Thousands)	June 30, 2016
Beginning Balance at January 1, 2016	$	11,934
Future Abandonment Obligation Incurred		282
Future Abandonment Obligation Settled		(4	)
Future Abandonment Obligation Cancelled or Sold		(4,568	)
Future Abandonment Obligation Revision of Estimated Obligation		—
Future Abandonment Obligation Accretion Expense		365
Total Future Abandonment Cost¹	$	8,009

Calendar Quarter Ending	West Texas Intermediate ("WTI") Average Price per Bbl (a)
12/31/2016	$	54.25
3/31/2017	$	56.25
6/30/2017	$	58.25
9/30/2017	$	60.25
12/31/2017	$	60.75
3/31/2018	$	61.25
6/30/2018	$	61.75
9/30/2018	$	62.25
12/31/2018	$	62.75
3/31/2019	$	63.25
6/30/2019	$	63.75

($ in Thousands)	June 30, 2016 (Unaudited)			December 31, 2015
Senior Notes, Net of Issuance Costs (a)	$	637,314		$	663,089
Premium on Senior Notes, Net		1,524			2,344
Senior Line of Credit, Net of Issuance Costs (b)(c)		141,237			109,396
Capital Leases and Other Obligations(c)		172			419
Total Debt		780,247			775,248
Less Current Portion of Long-Term Debt		(172	)		(402	)
Total Long-Term Debt	$	780,075		$	774,846

2016	$	165
2017		7
2018		—
2019		146,670
2020		640,251
Thereafter		6,160
Total^(a)	$	793,253

	As of June 30, 2016
	Range (price per Mcf)	Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Basis Differential Forward Curve - Dominion South	($0.34) - ($1.17)	$	(0.72	)	$	(4,431	)
Natural Gas Basis Differential Forward Curve - Texas Gas	($0.08) - ($0.12)	$	(0.10	)	$	(744	)


	As of December 31, 2015
	Range (price per Mcf)	Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Basis Differential Forward Curve - Dominion South	($0.27) - ($1.08)	$	(0.74	)	$	(5,468	)
Natural Gas Basis Differential Forward Curve - Texas Gas	($0.05) - ($0.17)	$	(0.12	)	$	(38	)

				Fair Value Measurements at June 30, 2016 Using:
($ in Thousands)	Total Carrying Value as of June 30, 2016			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(19,707	)	$	—	$	(14,532	)	$	(5,175	)

				Fair Value Measurements at December 31, 2015 Using:
($ in Thousands)	Total Carrying Value as of December 31, 2015			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	35,752		$	—	$	41,258		$	(5,506	)

	Year Ended December 31, 2015
Expected Dividend Yield		0.0	%
Risk-Free Interest Rate		1.0	%
Expected Volatility – Rex Energy		58.6	%
Expected Volatility – Peer Group	29.8%-85.0%
Market Index		35.6	%
Expected Life	Three Years

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2015		2,479,408		$	6.27
Awards		428,826			1.65
Forfeitures		(381,437	)		7.44
Vested		(245,468	)		10.67
Restricted stock awards, as of June 30, 2016		2,281,329		$	4.74

($ in Thousands)	Total
2016	$	15,342
2017		43,885
2018		47,328
2019		47,216
2020		46,060
Thereafter		528,816
Total	$	728,647

	<$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

	Other Performance Measurements
	For Three Months Ended June 30,				For Six Months Ended June 30,
	2016		2015		2016		2015
EBITDAX from Continuing Operations ($ in Thousands) (a)	$	19,024	$	19,739	$	27,495	$	47,964
LOE per Mcfe	$	1.39	$	1.37	$	1.40	$	1.38
G&A per Mcfe	$	0.27	$	0.42	$	0.29	$	0.46

	REX ENERGY CORPORATION (Registrant)
Date: August 5, 2016	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)

Exhibit Number		Exhibit Title
4.14		Registration Rights Agreement, dated as of March 31, 2016, by Rex Energy Corporation and the Guarantors for the Benefit of the Holders of Rex Energy Corporation’s 1.00%/8.00% Senior Secured Second Lien Notes due 2020 (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed with SEC on March 31, 2016).
4.15		First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of December 12, 2012, among Rex Energy Corporation, the Guarantors, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.4 to our Current Report on Form 8-K filed with SEC on March 31, 2016).
4.16		First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of July 17, 2014, among Rex Energy Corporation, the Guarantors, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.5 to our Current Report on Form 8-K filed with SEC on March 31, 2016).
10.1*		Eleventh Amendment to Amended and Restated Credit Agreement effective as of July 1, 2016, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto.
10.2*		Purchase and Sale Agreement dated June 14, 2016 by and among Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp., collectively as Seller, and Campbell Development Group, LLC as Purchaser.


31.1*		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2*		Certification of Chief Financial Officer (Principal Financial Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document