Rex Energy 10-Q 2017 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2017

OR

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

For the transition period from              to             .

Commission file number: 001-33610

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

366 Walker Drive

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐  (Do not check if a smaller reporting company)	Smaller reporting company	☒
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ☐

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

9,952,861 shares of common stock were outstanding on August 4, 2017.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2017

INDEX

			PAGE
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	5
		Consolidated Balance Sheets As of June 30. 2017 (Unaudited) and December 31, 2016	5
		Consolidated Statements of Operations (Unaudited) for the three and six-month periods ended June 30, 2017 and June 30, 2016	6
		Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the six-month period ended June 30, 2017	7
		Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2017 and June 30, 2016	8
		Notes to Consolidated Financial Statements (Unaudited)	9
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	39
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	53
	Item 4.	Controls and Procedures	55
PART II. OTHER INFORMATION			56
	Item 1.	Legal Proceedings	56
	Item 1A.	Risk Factors	56
	Item 6.	Exhibits	56
SIGNATURES			57
EXHIBIT INDEX			58

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information, including all of the estimates and assumptions, in this report 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 variations thereon or similar terminology.

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

• economic conditions in the United States and globally;

• domestic and global supply and demand for oil, natural gas liquids (“NGLs”), and natural gas;

• realized prices for oil, natural gas and NGLs and volatility of those prices;

• the adequacy and availability of capital resources, credit and liquidity, including, but not limited to, access to additional borrowing capacity and our inability to generate sufficient cash flow from operations to fund our capital expenditures and meeting working capital needs;

• our ability to comply with restrictions imposed by our term loan credit agreement, secured and unsecured indentures, and other existing and future financing arrangements;

• our ability to service our outstanding indebtedness;

• impairments of our natural gas, NGL and condensate asset values due to declines in commodity prices;

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

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

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

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

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

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

• drilling and operating risks;

• counterparty credit risks;

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

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

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

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

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

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

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

• changes in our drilling plans and related budgets;

• the success of prospect development and property acquisitions;

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

3

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

• our ability to maintain the listing of our securities on the NASDAQ Capital Market or any other exchange on which our securities trade; and

• other factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the Securities and Exchange Commission.

Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. 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.

4

Item 1. Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

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

	June 30, 2017 (unaudited)			December 31, 2016
ASSETS
Current Assets
Cash and Cash Equivalents	$	12,855		$	3,697
Accounts Receivable		23,762			25,448
Taxes Receivable		48			211
Short-Term Derivative Instruments		7,317			1,873
Inventory, Prepaid Expenses and Other		2,002			2,546
Total Current Assets		45,984			33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		977,665			1,053,461
Unevaluated Oil and Gas Properties		205,691			215,794
Other Property and Equipment		22,309			21,401
Wells and Facilities in Progress		59,807			21,964
Pipelines		21,289			18,029
Total Property and Equipment		1,286,761			1,330,649
Less: Accumulated Depreciation, Depletion and Amortization		(434,483	)		(475,205	)
Net Property and Equipment		852,278			855,444
Other Assets		2,488			2,492
Long-Term Derivative Instruments		4,820			2,212
Total Assets	$	905,570		$	893,923
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	46,235		$	40,712
Current Maturities of Long-Term Debt		834			764
Accrued Liabilities		32,791			37,207
Short-Term Derivative Instruments		6,563			25,025
Total Current Liabilities		86,423			103,708
Long-Term Derivative Instruments		9,450			7,227
Senior Secured Line of Credit, Net		—			113,785
Term Loans, Net		136,163			-
Senior Notes, Net		648,820			638,161
Other Long-Term Debt		3,627			3,409
Other Deposits and Liabilities		7,731			8,671
Future Abandonment Cost		9,658			8,736
Total Liabilities	$	901,872		$	883,697
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987    issued and outstanding on June 30, 2017 and December 31, 2016	$	1		$	1
Common Stock, $.001 par value per share, 100,000,000 shares authorized and    9,952,861 shares issued and outstanding on June 30, 2017 and 9,787,146    shares issued and outstanding on December 31, 2016.		10			10
Additional Paid-In Capital		651,659			650,669
Accumulated Deficit		(647,972	)		(640,454	)
Total Stockholders’ Equity		3,698			10,226
Total Liabilities and Stockholders’ Equity	$	905,570		$	893,923

See accompanying notes to the unaudited consolidated financial statements

5

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	47,457		$	31,271		$	99,522		$	56,944
Other Operating Revenue (Expense)		5			(6	)		11			7
TOTAL OPERATING REVENUE		47,462			31,265			99,533			56,951
OPERATING EXPENSES
Production and Lease Operating Expense		29,374			25,221			58,308			49,672
General and Administrative Expense		4,294			4,837			8,828			10,121
Gain on Disposal of Assets		(124	)		(4,307	)		(1,959	)		(4,295	)
Impairment Expense		3,032			25,139			4,577			35,780
Exploration Expense		99			803			319			1,738
Depreciation, Depletion, Amortization and Accretion		15,501			14,750			30,969			31,262
Other Operating (Income) Expense		(98	)		704			(118	)		1,030
TOTAL OPERATING EXPENSES		52,078			67,147			100,924			125,308
LOSS FROM OPERATIONS		(4,616	)		(35,882	)		(1,391	)		(68,357	)
OTHER INCOME (EXPENSE)
Interest Expense		(12,122	)		(11,439	)		(21,266	)		(24,469	)
Gain (Loss) on Derivatives, Net		10,386			(29,169	)		18,766			(25,120	)
Other Income (Expense)		20			12			(7	)		12
Debt Exchange Expense		—			(533	)		—			(9,014	)
(Loss) Gain on Extinguishments of Debt		(3,271	)		23,707			(3,022	)		23,707
TOTAL OTHER INCOME (EXPENSE)		(4,987	)		(17,422	)		(5,529	)		(34,884	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(9,603	)		(53,304	)		(6,920	)		(103,241	)
Income Tax Benefit (Expense)		—			393			—			(2,321	)
NET LOSS FROM CONTINUING OPERATIONS		(9,603	)		(52,911	)		(6,920	)		(105,562	)
Loss From Discontinued Operations, Net of Income Taxes		—			(1,683	)		—			(9,173	)
NET LOSS		(9,603	)		(54,594	)		(6,920	)		(114,735	)
Preferred Stock Dividends		(598	)		(1,723	)		(1,196	)		(3,828	)
Effect of Preferred Stock Conversions		—			72,316			—			72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(10,201	)	$	15,999		$	(8,116	)	$	(46,247	)
Earnings per common share:
Basic - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders		(1.03	)	$	2.45		$	(0.83	)	$	(5.79	)
Basic - Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders		-			(0.23	)		-			(1.43	)
Basic - Net Income (Loss) Attributable to Rex Energy Common Shareholders		(1.03	)	$	2.22		$	(0.83	)	$	(7.22	)
Basic - Weighted Average Shares of Common Stock Outstanding		9,881			7,180			9,825			6,404
Diluted - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders		(1.03	)	$	2.45		$	(0.83	)	$	(5.79	)
Diluted - Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders		-			(0.23	)		-			(1.43	)
Diluted - Net Income (Loss) Attributable to Rex Energy Common Shareholders		(1.03	)	$	2.22		$	(0.83	)	$	(7.22	)
Diluted - Weighted Average Shares of Common Stock Outstanding		9,881			7,180			9,825			6,404

See accompanying notes to the unaudited consolidated financial statements

6

REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE SIX-MONTHS ENDED JUNE 30, 2017

(Unaudited, in Thousands)

	Common Stock				Preferred Stock
	Shares		Par Value		Shares		Par Value		Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Equity
BALANCE December 31, 2016		9,787	$	10		4	$	1	$	650,669		$	(640,454	)	$	10,226
Equity Based Compensation		—		—		—		—		571			—			571
Issuance of Common Stock for Debt Extinguishments		84		—		—		—		467			—			467
Issuance of Restricted Stock, Net of    Forfeitures		82		—		—		—		—			—			—
Effect of Reverse Stock Split		—		—		—		—		(48	)		—			(48	)
Payment of Preferred Dividends in Arrears		—		—		—		—		—			(598	)		(598	)
Net Loss		—		—		—		—		—			(6,920	)		(6,920	)
BALANCE June 30, 2017		9,953	$	10		4	$	1	$	651,659		$	(647,972	)	$	3,698

See accompanying notes to the unaudited consolidated financial statements

7

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Six Months Ended June 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(6,920	)	$	(114,735	)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion		30,969			36,345
(Gain) Loss on Derivatives		(18,766	)		25,120
Cash Settlements of Derivatives		(5,525	)		30,340
Non-cash Dry Hole Expense		13			870
Equity-based Compensation Expense		571			1,305
Impairment Expense		4,577			39,323
Amortization of net Bond Discount and Deferred Debt Issuance Costs		—			538
Non-cash Interest Expense related to Debt Restructurings and Exchanges		12,431			8,126
Loss (Gain) on Extinguishments of Debt		3,022			(23,757	)
Gain on Sale of Assets		(1,959	)		(4,338	)
Other Non-cash Expense		41			131
Changes in operating assets and liabilities
Accounts Receivable		7,229			(14,772	)
Taxes Receivable		163			—
Inventory, Prepaid Expenses and Other Assets		52			1,118
Accounts Payable and Accrued Liabilities		(1,484	)		10,425
Other Assets and Liabilities		(1,104	)		(676	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		23,310			(4,637	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		24,513			190
Proceeds from Joint Venture for Reimbursement of Capital Costs		—			19,461
Acquisitions of Undeveloped Acreage		(1,783	)		(5,900	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(54,004	)		(37,738	)
NET CASH USED IN INVESTING ACTIVITIES		(31,274	)		(23,987	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit		171,000			50,400
Repayments of Long-Term Debt and Line of Credit		(145,170	)		(15,230	)
Repayments of Loans and Other Notes Payable		(319	)		(361	)
Debt Issuance Costs		(7,791	)		(3,838	)
Payment of Preferred Dividends in Arrears		(598	)		—
NET CASH PROVIDED BY FINANCING ACTIVITIES		17,122			30,971
NET INCREASE IN CASH		9,158			2,347
CASH – BEGINNING		3,697			1,091
CASH – ENDING	$	12,855		$	3,438
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	$	12,855		$	3,438
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	$	8,494		$	24,260
Cash Paid (Received) for Income Taxes		(163	)		29
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations		—			991
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin	$	(1,893	)	$	—
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets		5,000			—
Increase (Decrease) in Accrued Liabilities for Capital Expenditures		1,652			(1,688	)
Increase in Other Long Term Debt - Capital Lease Equipment Financing		607			—
Decrease in Senior Notes carrying value net of Issuance Costs, Deferred Gain on      Exchanges, and Net Premium / Discount due to Debt to Equity Conversions		(879	)		(28,735	)
Decrease in  Bond Interest Payable due to Debt to Equity Conversions		(12	)		(719	)
Increase in Common Stock outstanding due to Debt to Equity Conversions		467			5,696

See accompanying notes to the unaudited consolidated financial statements

8

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent natural gas, natural gas liquid (“NGL”) and condensate company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian 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 natural gas, NLG and condensate 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 Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

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

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016.

Reverse Stock Split

On May 12, 2017, we effected a one-for-ten reverse stock split. As a result of the reverse stock split, each ten shares of our common stock automatically combined into and became one share of our common stock. Any fractional shares which would have otherwise been due as a result of the reverse split were rounded up to the nearest whole share. As a result of the reverse stock split, we reduced the issued number of common shares from 99.0 million to 9.9 million. The reverse stock split automatically and proportionately adjusted, based on the one-for-ten split ratio, all issued and outstanding shares of our common stock, as well as common stock underlying stock options, warrants and other derivative securities outstanding at the time of the effectiveness of the reverse stock split. The exercise price on outstanding equity based-grants proportionately increased, while the number of shares available under our equity-based plans also was proportionately reduced. Share and per share data for the periods presented reflect the effects of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

Discontinued Operations

In 2016, we divested all of our Illinois Basin assets and operations. The sale closed in August 2016, with an effective date of July 1, 2016. As a result of this transaction, the 2016 results of operations of our Illinois Basin operations have been classified as Discontinued Operations in the accompanying Consolidated Statements of Operations for the year ended December 31, 2016.  

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.

9

2. FUTURE ABANDONMENT COST

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

Accretion expense totaled $0.5 million and $1.0 million for the three and six months ended June 30, 2017, respectively, and $0.1 million and $0.4 million for the three and six months ended June 30, 2016, respectively.  These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.

($ in Thousands)	June 30, 2017
Beginning Balance at January 1, 2017	$	9,865
Future Abandonment Obligation Incurred	$	1,062
Future Abandonment Obligation Settled	$	(1,051	)
Future Abandonment Obligation Cancelled or Sold	$	(262	)
Future Abandonment Obligation Revision of Estimated Obligation	$	57
Future Abandonment Obligation Accretion Expense	$	1,042
Total Future Abandonment Cost1	$	10,713

¹ Includes approximately $1.1 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

Illinois Basin Operations

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 agreed to purchase, subject to certain parameters and provisions for adjustment customary for transactions of this type, all of our oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 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 2016 and received the additional proceeds of approximately $38.0 million during the third and fourth quarters of 2016. An addendum executed in conjunction with the Agreement allowed for the Company 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 ended 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 the applicable quarter. As of June 30, 2017, the first three of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds related to those measurement periods.  As of June 30, 2017, we have the potential to receive up to $7.2 million of additional proceeds, during the eight remaining measurement periods. For additional information, see Note 8, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

Calendar Quarter Ending	West Texas Intermediate ("WTI")  Average Price per Bbl (a)
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

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(a) 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).

Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day.  The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations.  As of June 30, 2017 and December 31 2016, we had no remaining assets or liabilities related to our former Illinois Basin operations. The results of operations of our Illinois Basin operations are reported as Discontinued Operations for the three and six months ended June 30, 2016, in our Consolidated Statements of Operations.

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 month periods ended June 30, 2017 and 2016.

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
($ in Thousands)	2017		2016			2017		2016
Revenues:
Oil Sales	$	—	$	6,393		$	—	$	11,213
Total Operating Revenue		—		6,393			—		11,213
Costs and Expenses:
Production and Lease Operating Expense		—		5,029			—		10,725
General and Administrative Expense		—		659			—		1,437
Gain on Disposal of Assets		—		(2	)		—		(43	)
Impairment Expense		—		—			—		3,543
Exploration Expense		—		85			—		143
Depreciation, Depletion, Amortization and Accretion		—		2,186			—		5,083
Interest Expense		—		1			—		3
Other Income		—		(2	)		—		(3	)
Total Costs and Expenses		—		7,956			—		20,888
Loss From Discontinued Operations, Before Income Taxes		—		(1,563	)		—		(9,675	)
Income Tax Expense		—		(120	)		—		502
Loss From Discontinued Operations, Net of Taxes	$	—	$	(1,683	)	$	—	$	(9,173	)
Production:
Crude Oil (Bbls)		—		150,980			—		308,720

4. BUSINESS AND OIL AND GAS PROPERTY DISPOSITIONS

Benefit Street Partners, LLC

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 agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and 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 paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of June 30, 2017. BSP has paid approximately $103.0 million for its interest in elected wells as of June 30, 2017. 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 it participates. As of June 30, 2017, 34 of the 45 committed wells were in line and producing, four were completed waiting to go in line, and seven wells were drilled and awaiting completion.

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.

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Diversified Oil & Gas, LLC

On May 20, 2016, we entered into a Purchase and Sale Agreement (the “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 $0.1 million. Included in the sale were approximately 300 wells, pipelines and support equipment. The sale of well properties generatedapproximately $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.

Illinois Basin Operations

As described in Note 3, Discontinued Operations/Assets Held for Sale, we sold our Illinois Basin assets and operations pursuant to a purchase and sale agreement with Campbell in August 2016.

Sale of Warrior South Assets

On January 11, 2017, we, together with MFC Drilling, Inc. (“MFC”), and ABARTA Oil & Gas Co., Inc. (“ABARTA”) (together, the “Sellers”) sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation (“Antero”). These interests comprised our Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to Rex, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017.  Approximately $5.0 million of the total proceeds due to us will be held in escrow and will be released in January 2018, net of post-closing adjustments. The proceeds held in escrow are classified as accounts receivable on our Consolidated Balance Sheet as of June 30, 2017. The sale of assets resulted in a gain on disposal of assets of approximately $1.8 million in January 2017. This gain includes the additional proceeds held in escrow, which we anticipate receiving in January 2018. The sale of assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to us, and approximately 6,200 gross acres, with 4,100 acres net to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down our revolving line of credit and for general corporate purposes.

5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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

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

2) Identify the performance obligations in the contract.

3) Determine the transaction price.

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

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

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

1) Retrospectively to each prior reporting period presented.

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

In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, after December 15, 2017.

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Early adoption is not permitted. We continue to evaluate the available adoption methods. We are currently analyzing the potential impact of the standard on each of our revenue contracts by identifying differences between current recognition policies and the guidance set forth in the standard. As of June 30, 2017, we were still evaluating the potential impact of this standard on our results of operations and internal control environment.

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:

• A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and

• A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

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 the potential impact of this standard on our results of operations and internal control environment.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues:

• debt prepayment or debt extinguishment costs;

• settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing;

• contingent consideration payments made after a business combination;

• proceeds from the settlement of insurance claims;

• proceeds from the settlement of corporate-owned life insurance policies;

• distributions received from equity method investees;

• beneficial interest in securitization transactions; and

• separately identifiable cash flows and application of the Predominance Principle.

Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

6. CONCENTRATIONS OF CREDIT RISK

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions (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, 2017, approximately 95.3% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 50.7% of commodity sales. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of condensate and gas sales as well as the quantity of purchasers.  

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7. LONG-TERM DEBT

Term Loan

On April 28, 2017 (the “Effective Date”), we entered into a term loan agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent (in such capacity, the “Administrative Agent”), AGES, as collateral agent (in such capacity, the “Collateral Agent”), Macquarie Bank Limited, as issuing bank (in such capacity, the “Issuing Bank”), and the lenders from time to time party thereto. The Term Loan replaced our existing amended and restated senior secured revolving credit agreement (the “Existing Credit Agreement”).  The Term Loan provides for a $143,500,000 secured term loan facility (the “Term Facility”) and a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit sub-facility (the “Letter of Credit Sub-facility”).  The proceeds of the initial loans under the Term Loan were used for refinancing of loans under the Existing Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility may be used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes.  The maximum commitments of the lenders under the Term Loan are currently limited to $300,000,000.  Amounts borrowed and repaid may not be re-borrowed. The maturity date for the loans under the Term Facility and the loans drawn under the Delayed Draw Term Facility is the earlier of (a) April 28, 2021 and (b) the date that is six months prior to the maturity of the Company’s 1.00/8.00% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) unless less than $25,000,000 Second Lien Notes are then outstanding and no Event of Default (as defined in the Term Loan) exists on such date.  The commitments under the Delayed Draw Term Facility expire if not drawn prior to the earlier of (a) April 28, 2018 (which date may be extended for one year with lender consent) and (b) the date upon which the Borrower terminates such commitments. As of June 30, 2017, we had $143.5 million borrowings outstanding and approximately $46.3 million in outstanding undrawn letters of credit. We incurred approximately $3.5 million in debt issuance costs and $4.3 million in original issue discount (“OID”) related to the initial Term Loan borrowing. From April 28, 2017 through June 30, 2017, we amortized $0.2 million of debt issuance costs and $0.2 million of OID. The amortization of debt issuance costs and OID are reported as Interest Expense in our Consolidated Statement of Operations.

Borrowings under the Term Loan bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. The “Adjusted LIBO Rate” is equal to the product of the three month LIBOR rate multiplied by the statutory reserve rate.  Upon the occurrence and continuance of an Event of Default all outstanding loans shall bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable on the last Business Day of each March, June, September and December.  Under the Term Loan the Company will pay a 3.5% commitment fee on any unused portion of the Delayed Draw Term Facility.

The Term Loan requires us to prepay the loans with 100% of the net cash proceeds received from certain asset sales, swap terminations, incurrences of borrowed money indebtedness, casualty events and equity issuances, subject to certain exceptions and specified reinvestment rights.  Prepayments based on 75% of excess cash flow are required until no more than $287,950,000 in Second Lien Notes remain outstanding, at which time, prepayments based on 50% of excess cash flow will be required.  Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan are subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and 1 day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount.

The Term Loan contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividend payments, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

The Term Loan also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after December 31, 2017, the PDP Coverage Ratio (as defined in the Term Loan) will not be less than 1.65 to 1.00; (2) as of the last day of any fiscal quarter ending on or after March 31, 2017, the ratio of Net Senior Secured Debt (as defined in the Term Loan) as of such date to EBITDAX  (as defined in the Term Loan) for the period of four fiscal quarters then ending on such day will not be greater than 3.25 to 1.00 (provided that EBITDAX for the four fiscal quarters ending on (i) March 31, 2017 shall be EBITDAX for the fiscal quarter then ending multiplied by four and (ii) June 30, 2017 shall be EBITDAX for the two fiscal quarters then ending multiplied by two); and (3) as of the last day of any fiscal quarter ending on or after September 30, 2017the ratio of EBITDAX for the four fiscal quarters then ending to cash interest expense will not be less than (i) 1.00 to 1.00 for any fiscal quarter ending on or before September 30, 2017 and (ii) 1.30 to 1.00 for each fiscal quarter thereafter. As of June 30, 2017, our Net Senior Secured Debt to EBITDAX Ratio was 2.33 to 1.00.

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Our obligations under the Credit Agreement may be accelerated upon the occurrence of an Event of Default (as such term is defined in the Term Loan). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the Term Loan).

Obligations under the Term Loan are secured by mortgages on our oil and gas properties. In connection with the Term Loan, we, including our wholly owned subsidiaries, Rex Energy I, LLC, Rex Energy Operating Corp., PennTex Resources Illinois, Inc., Rex Energy IV, LLC, and R.E. Gas Development, LLC (collectively, the “Guarantors” and together with us, the “Grantors”), entered into an amended and restated guaranty and collateral agreement, dated as of April 28, 2017, in favor of the Collateral Agent for the lenders from time to time party to the Term Loan, the secured swap parties and the Issuing Bank (the “Guaranty and Collateral Agreement”).  Pursuant to the Guaranty and Collateral Agreement, each of the Guarantors, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Term Loan. In addition, each Grantor granted, as security for the prompt and complete payment and performance when due of such Grantor’s obligations, a security interest in substantially all of its assets, including equity interests in other Guarantors, as applicable.

Senior Secured Line of Credit

On April 28, 2017, we terminated our Senior Secured Line of Credit (the “Senior Credit Facility”) with Royal Bank of Canada, as Administrative Agent and the lenders from time to time parties thereto. We used the initial term draw borrowing under the Term Loan to repay and retire in full the Senior Credit Facility. In conjunction with the retirement of the Senior Credit Facility, we wrote off $3.4 million of associated unamortized debt issuance costs, included in Loss on Extinguishments of Debt in our Consolidated Statement of Operations.  We had $117.7 million borrowings outstanding as of December 31, 2016.    

Senior Notes

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 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 $9.1 million in third-party debt issuance costs during the year ended December 31, 2016. 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 during the remainder of 2016, 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 $27.7 million of our remaining Existing Notes and $45.7 million of our outstanding New Notes, in exchange for the issuance of a total of approximately 22.7 million shares of unrestricted common stock during the year ended December 31, 2016. In the six months ended June 30, 2017, we completed debt-for equity exchanges with certain holders of our Existing Notes.  These exchanges resulted in the retirement of approximately $0.9 million of our remaining Existing Notes, in exchange for approximately 0.1 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the Company for the six months ended June 30, 2017 of approximately $0.4 million, presented as Gain on Extinguishments of Debt in our Consolidated Statements of Operations.

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

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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 and Deferred Gain on Exchanges on our Consolidated Balance Sheets.

The Senior Notes are governed 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 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, 2017, our Fixed Charge Coverage Ratio was 1.05 to 1.00.  We expect our Fixed Charge Coverage Ratio to improve based on our projections of decreased interest expense related to the New Notes, increased production and improved price realizations. As of June 30, 2017, we were limited to incurring approximately $75.2 million of additional 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, 2017 and December 31, 2016, we had recorded on our Consolidated Balance Sheets approximately $11.2 million and $3.6 million, respectively, of net premium related to the Senior Notes. The amortization of our net premium during the three and six months ended June 30, 2017, which follows the effective interest method, was approximately $3.8 million and $7.6 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.

			June 30, 2017
			Principal			Unamortized net Premium / Discount			Unamortized Debt Issuance Costs			Unamortized Deferred Gain on Debt Restructurings		Net Carrying Value
Term Loans, Net
	Term Loan Draw - due April 2020		$	143,500		$	(4,072	)	$	(3,265	)	$	-	$	136,163
Senior Notes, Net
	8.875% Senior Notes due 2020		$	7,333		$	23		$	(92	)	$	-	$	7,264
	6.25% Senior Notes due 2022			5,363			-			(73	)		-		5,290
	1% / 8%  Second Lien Senior Notes due 2020			587,606			(11,250	)		26,915			32,995		636,266
			$	600,302		$	(11,227	)	$	26,750		$	32,995	$	648,820
Other Long-Term Debt
	Long-Term Capital Leases - Equipment Financing
		Due March, 2021	$	699
		Due June, 2021		2,045
		Due September, 2021		1,717
		Total Capital Lease Obligations	$	4,461
		Less: Current Portion of Capital Leases		(834	)
			$	3,627

The weighted average interest rate on borrowed balances under the Term Loan for the three and six months ended June 30, 2017 was approximately 10.1% and 9.99%, respectively.  The weighted average interest rate on the Senior Secured Line of Credit for the three and six months ended June 30, 2017 was approximately 4.9% and 4.1%, respectively. The average interest rate on our capital leases for the three and six months ended June 30, 2017 was approximately 17.2% and 14.4%, respectively.

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			December 31, 2016
			Principal		Unamortized net Premium / Discount			Unamortized Debt Issuance Costs			Unamortized Deferred Gain on Debt Restructurings		Net Carrying Value
Senior Secured Line of Credit, Net
	Revolving Senior Credit Facility		$	117,670	$	-		$	(3,885	)	$	-	$	113,785
Senior Notes, Net
	8.875% Senior Notes due 2020		$	7,573	$	26		$	(107	)	$	-	$	7,492
	6.25% Senior Notes due 2022			5,648		-			(82	)		-		5,566
	1% / 8%  Second Lien Senior Notes due 2020			587,956		(3,627	)		8,098			32,676		625,103
			$	601,177	$	(3,601	)	$	7,909		$	32,676	$	638,161
Other Long-Term Debt
	Long-Term Capital Leases and Other Notes Payable- Equipment Financing
		Due March, 2021											$	760
		Due June, 2021												2,225
		Due September, 2021												1,174
		Total Capital Lease Obligations											$	4,159
		Other Notes Payable												14
		Total Capital Lease and Note Payable Obligations											$	4,173
		Less: Current Portion of Capital Leases and Other Notes Payable												(764	)
													$	3,409

The following is the principal maturity schedule for debt outstanding as of June 30, 2017:

2017	$	399
2018		908
2019		1,076
2020		739,715
2021		802
Thereafter		5,363
Total(a)	$	748,263

(a) Excludes $15.3 million of net unamortized premium/discount, $23.5 million of net unamortized debt issuance costs, and $33.0 million of unamortized deferred gain on debt restructurings.

8. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of June 30, 2017 and December 31, 2016, 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 two 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

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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 paid net cash settlements of $2.1 million and $5.5 million in relation to our commodity derivatives during the three and six months ended June 30, 2017, respectively and 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.

As of June 30, 2017, we had approximately 75.0% of our annualized condensate production hedged through the remainder of 2017, over 90.0% and 60.0% of our annualized natural gas production hedged through the remainder of 2017 and 2018, respectively, and over 70.0% and 50.0% of our annualized NGL production hedged through the remainder of 2017 and 2018, respectively. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our natural gas, condensate and NGL production.

Contingent Consideration – Sale of Illinois Basin Operations

In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets as defined in the contract are achieved at specified future dates.  See Note 3, Discontinued Operations / Assets Held for Sale, to our Consolidated Financial Statements for additional information regarding the terms of the contract. We have evaluated the contract and concluded that it meets the definition and requirements for accounting treatment as a derivative instrument, as prescribed in ASC 815-10-15-83. We recorded the contract at its initial fair value of approximately $1.2 million as additional consideration in the calculation of the gain on the sale of the assets. Fair value was determined through application of mathematical models designed to provide fair value estimates utilizing probability measures and the market index measures underlying the contract. The fair value will be adjusted at each future reporting period for the duration of the contract, which concludes June 30, 2019. As of June 30, 2017 and December 31, 2016, the contingent consideration contract was valued at $1.0 million and $2.9 million, respectively.

Interest Rate Derivatives

We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of June 30, 2017, and December 31, 2016, we had $143.5 million and $117.7 million outstanding under our Term Loan and our Senior Credit Facility, respectively, which is subject to variable rates of interest and $600.3 million and $601.2 million, respectively, 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, 2017 and December 31, 2016, 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. When applicable, we recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense.

Derivative Instruments from Continuing Operations

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, 2017 and 2016:  

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
($ in Thousands)	2017			2016			2017			2016
Oil	$	791		$	(2,494	)	$	1,934		$	(2,169	)
Natural Gas		6,132			(18,666	)		6,072			(13,302	)
NGLs		3,938			(8,093	)		12,653			(9,714	)
Refined Products		—			84			—			65
Contingent Consideration		(475	)		—			(1,893	)		—
Gain (Loss) on Derivatives, Net	$	10,386		$	(29,169	)	$	18,766		$	(25,120	)

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Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $3.9 million and approximately $28.2 million at June 30, 2017 and December 31, 2016, respectively.

Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2017 consisted of:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2017 - Swaps		30,000	Bbls	$	—	$	—	$	—	$	54.00		$	175
2017 - Three-Way Collars		78,000	Bbls		39.62		49.23		61.35		—			228
2018 - Swaps		60,000	Bbls		—		—		—		54.00			350
2018 - Collars		18,000	Bbls		—		53.00		60.00		—			113
2018 - Three-Way Collars		60,000	Bbls		43.00		52.00		62.30		—			211
2019 - Swaps		31,500	Bbls		—		—		—		51.00			21
2019 - Three-Way Collars		21,000	Bbls		37.50		47.50		59.00		—			6
2020 - Swaps		24,000	Bbls		—		—		—		51.00			21
2020 - Three-Way Collars		3,000	Bbls		37.50		47.50		59.00		—			1
2021 - Swaps		6,000	Bbls		—		—		—		51.00			5
		331,500	Bbls										$	1,131
Natural Gas
2017 - Swaps		5,990,000	Mcf		—		—		—		3.12		$	234
2017 - Swaptions		1,200,000	Mcf		—		—		—		3.33			269
2017 - Cap Swaps		1,800,000	Mcf		2.25		—		—		2.70			(703	)
2017 - Collars		1,100,000	Mcf		—		2.62		3.25		—			(48	)
2017 - Three-Way Collars		8,490,000	Mcf		2.29		2.98		3.86		—			669
2017 - Calls		1,500,000	Mcf		—		—		3.64		—			(154	)
2017 - Basis Swaps - Dominion South		5,635,000	Mcf		—		—		—		(0.80	)		(688	)
2017 - Basis Swaps - Texas Gas		7,360,000	Mcf		—		—		—		(0.13	)		4
2018 - Swaps		15,335,000	Mcf		—		—		—		3.10			1,321
2018 - Swaptions		—	Mcf		—		—		—		—			(143	)
2018 - Three-Way Collars		8,775,000	Mcf		2.30		2.89		3.58		—			228
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(527	)
2018 - Collars		450,000	Mcf		—		3.20		3.65		—			38
2018 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.83	)		(3,029	)
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf								(0.13	)		8
2019 - Swaps		6,350,000	Mcf		—		—		—		2.91			26
2019 - Three-Way Collars		5,000,000	Mcf		2.35		2.85		3.60		—			46
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(3,256	)
2020 - Swaps		3,660,000	Mcf		—		—		—		2.90			(29	)
2020 - Three-Way Collars		1,810,000	Mcf		2.35		2.85		3.60		—			46
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(1,722	)
2021 - Swaps		900,000	Mcf		—		—		—		2.90			(7	)
2021 - Three-Way Collars		300,000	Mcf		2.35		2.85		3.60		—			12
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
		143,535,000	Mcf										$	(9,509	)
NGLs
2017 - C3+ NGL Swaps		841,000	Bbls		—		—		—		29.70		$	(779	)
2017 - Ethane Swaps		450,000	Bbls		—		—		—		10.50			(54	)
2018 - C3+ NGL Swaps		1,110,000	Bbls		—		—		—		31.50			3,102
2018 - Ethane Swaps		750,000	Bbls		—		—		—		13.02			539
2019 - C3+ NGL Swaps		353,250	Bbls		—		—		—		26.04			200
2019 - C5 Collars		113,040	Bbls		—		44.94		55.02		—			5
2019 - Ethane Swaps		480,000	Bbls		—		—		—		13.02			130
2020 - C3+ NGL Swaps		135,000	Bbls		—		—		—		24.78			256
2020 - C5 Collars		28,260	Bbls		—		44.94		55.02		—			1
2020 - Ethane Swaps		48,000	Bbls		—		—		—		13.44			(3	)
2021 - C3+ NGL Swap		30,000	Bbls		—		—		—		24.78			62
2021 - Ethane Swaps		9,000	Bbls		—		—		—		13.44			(1	)
		4,347,550	Bbls										$	3,458

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The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 is summarized below:

	June 30,			December 31,
($ in Thousands)	2017			2016
Short-Term Derivative Assets:
Crude Oil—Three-Way Collars	$	333		$	—
Crude Oil—Swaps		350			—
Crude Oil—Collars		113			—
NGL—Swaps		3,210			—
Natural Gas—Swaps		1,292			206
Natural Gas—Cap Swaps		—			61
Natural Gas—Collars		63			—
Natural Gas—Basis Swaps		211			232
Natural Gas—Three-Way Collars		1,141			151
Natural Gas—Swaption		269			—
Contingent Consideration - Sale of Illinois Basin		335			1,223
Total Short-Term Derivative Assets	$	7,317		$	1,873
Long-Term Derivative Assets:
Crude Oil—Three-Way Collars	$	113		$	—
Crude Oil—Swaps		222			—
NGL—Swaps		2,553			—
NGL—Collars		14			—
Natural Gas—Swaps		760			206
Natural Gas—Basis Swaps		53			293
Natural Gas—Three-Way Collars		396			—
Contingent Consideration - Sale of Illinois Basin		709			1,713
Total Long-Term Derivative Assets	$	4,820		$	2,212
Total Derivative Assets	$	12,137		$	4,085
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	—		$	(86	)
Crude Oil—Deferred Put Spread		—			(9	)
Crude Oil—Three-Way Collars		—			(132	)
Crude Oil—Swaps		—			(220	)
NGL—Swaps		(2,211	)		(9,895	)
Natural Gas—Three-Way Collars		(368	)		(2,397	)
Natural Gas—Cap Swaps		(703	)		(3,364	)
Natural Gas—Collars		(73	)		(873	)
Natural Gas—Basis Swaps		(2,291	)		(640	)
Natural Gas—Call		(418	)		(1,478	)
Natural Gas—Swaption		(71	)		(1,258	)
Natural Gas—Swaps		(428	)		(4,673	)
Total Short - Term Derivative Liabilities	$	(6,563	)	$	(25,025	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	—		$	(58	)
Crude Oil—Swaps		—			(146	)
NGL—Swaps		(100	)		(2,200	)
NGL—Collars		(8	)		—
Natural Gas—Swaps		(79	)		(1,004	)
Natural Gas—Swaption		(72	)		(167	)
Natural Gas—Basis Swaps		(8,760	)		(1,260	)
Natural Gas—Collars		—			(115	)
Natural Gas—Call		(263	)		(491	)
Natural Gas—Three-Way Collars		(168	)		(1,786	)
Total Long-Term Derivative Liabilities	$	(9,450	)	$	(7,227	)
Total Derivative Liabilities	$	(16,013	)	$	(32,252	)

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.

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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 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, 2017 and December 31, 2016, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

We had no Level 3 commodity derivative contracts outstanding as of June 30, 2017 or December 31, 2016.

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, 2017 and for the year ended December 31, 2016 there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:

				Fair Value Measurements at June 30, 2017
($ in Thousands)	Total Carrying Value as of June 30, 2017			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(3,876	)	$	—	$	(3,876	)	$	—
				Fair Value Measurements at December 31, 2016
($ in Thousands)	Total Carrying Value as of December 31, 2016			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(28,167	)	$	—	$	(28,167	)	$	—

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, 2017 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, 2017 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, 2017 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.  

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Future Abandonment Cost

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

Financial Instruments Not Recorded at Fair Value

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

	June 30, 2017				December 31, 2016
($ in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Notes, Net	$	648,820	$	288,156	$	638,161	$	147,605
Secured Line of Credit, Net of Issuance Costs		—		—		113,785		113,785
Term Loans, Net		136,163		136,163		—		—
Capital Leases and Other Obligations		4,461		3,074		4,173		3,234
Total	$	789,444	$	427,393	$	756,119	$	264,624

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.

Other Fair Value Measurements

During the six months ended June 30, 2017 and 2016, we recorded other than temporary impairments of $4.6 million and $35.8 million, respectively, 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 3 within the fair value hierarchy. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

9. INCOME TAXES

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

Income tax included in continuing operations was as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
($ in Thousands)	2017			2016			2017			2016
Income Tax Benefit (Expense)	$	—		$	393		$	—		$	(2,321	)
Effective Tax Rate		0.0	%		0.7	%		0.0	%		-2.2	%

Management estimates the annual effective income tax rate quarterly, based on current annual forecasted results. Items unrelated to current year ordinary income are recognized entirely in the period identified as a discrete item of tax. The quarterly

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income tax provision is comprised of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items. The Company accounts for the tax effects of discontinued operations as a discrete item and therefore recognizes the full tax effects of discontinued operations in the same period that the pretax income or loss from discontinued operations is recognized. This approach results in a tax benefit being recorded in continuing operations to offset the tax charge on the gain recorded in discontinued operations, when a full valuation allowance exists on the deferred tax attributes of the Company’s entire operations.

For the six months ended June 30, 2017, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of maintaining a full valuation allowance against our deferred tax assets.   

For the six months ended June 30, 2016 the estimated annual effective tax rate applied to ordinary losses from continuing operations was -2.2%.  The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets coupled with recognizing tax benefits in continuing operations for the effect of taxable income generated by our discontinued operations. To a lesser extent, the annual effective rate is also influenced by alternative minimum tax with no corresponding deferred tax benefit due to the full valuation allowance, and state taxes in certain tax paying jurisdictions.  The Company’s alternative minimum tax due for 2016 is driven primarily by cancellation of debt income of $543.2 million related to the Senior Note exchanges discussed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. The Company recorded an expense for income taxes from continuing operations of $2.3 million, for federal and state income taxes for the six months ended June 30, 2016.

Income tax payments made during the six months ended June 30, 2017 were $2.0 million, and payments made during the six months ended June 30, 2016 were negligible.  Tax refunds received during the six months ended June 30, 2017 were approximately $0.2 million, and refunds received during the six months ended June 30, 2016 were negligible.

10. CAPITAL STOCK

Reverse Stock Split

As discussed in Note 1, Basis of Presentation and Principles of Consolidation, references to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

Common Stock

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. On May 5, 2017, the Company’s common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017. As of June 30, 2017, we have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2017 and December 31, 2016, shares of common stock issued and outstanding totaled 9,952,861 and 9,787,146, respectively.  During the six months ended June 30, 2017, we issued approximately 0.1 million shares of our common stock in conjunction with debt for equity exchanges completed 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.

Preferred Stock

As of both June 30, 2017 and December 31, 2016, 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 3,987. During the six months ended June 30, 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 0.9 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. In May 2017, we paid a cash dividend of $150.00 per share for the period of November 15, 2015 to February 15,

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2016 in the aggregate amount of $0.6 million. As of June 30, 2017, accumulated dividends in arrears totaled $3.0 million.  While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulation of unpaid dividends during the current reporting period is included in our Net Income (Loss) in the determination of Net Income (Loss) Attributable to Common Shareholders and related earnings per share calculations.

If dividends are in arrears and unpaid for six or more quarterly periods (whether or not consecutive), 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.

11. EMPLOYEE BENEFIT AND EQUITY PLANS

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.

Stock Options

During the six months ended June 30, 2017, no new options to purchase shares of our common stock were granted. During the six months ended June 30, 2016, we issued 88,892 options to purchase shares of our common stock to 34 employees.  Stock-based compensation expense from continuing operations relating to stock options outstanding for the three and six months ended June 30, 2017 was $0.1 million and $0.2 million, respectively. Stock-based compensation expense from continuing operations relating to stock options outstanding for each of the three and six months ended June 30, 2016 was $0.1 million. 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 during the six months ended June 30, 2017. There was no tax benefit related to stock option exercises for each of the six-month periods ended June 30, 2017 and 2016.

A summary of the status of our issued and outstanding stock options as of June 30, 2017 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding at June 30, 2017		Weighted-Average Exercise Price		Number Exercisable at June 30, 2017		Weighted-Average Exercise Price
	9.70		2,750	$	9.70		918	$	9.70
	16.90		75,352	$	16.90		25,125	$	16.90
	40.50		4,000	$	40.50		—	$	40.50
	49.00		4,000	$	49.00		666	$	49.00
	50.40		3,070	$	50.40		3,070	$	50.40
	95.00		5,000	$	95.00		5,000	$	95.00
	99.90		12,959	$	99.90		12,959	$	99.90
	104.20		2,217	$	104.20		2,217	$	104.20
	223.40		3,000	$	223.40		3,000	$	223.40
			112,348	$	39.91		52,955	$	62.16

The weighted average remaining contractual term for options outstanding at June 30, 2017 was 4.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at June 30, 2017 was 3.2 years and there was no aggregate intrinsic value.  As of June 30, 2017, unrecognized compensation expense related to stock options was $0.2 million.  

Restricted Stock Awards

During the six-month period ended June 30, 2017, the Compensation Committee approved the issuance of an aggregate of 101,237 shares of restricted common stock to 28 employees. During the six-month period ended June 30, 2016, the Compensation Committee approved the issuance of an aggregate of 42,883 shares of restricted stock to 25 employees. 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.

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

	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

During the six months ended June 30, 2017, 17,952 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.1 million for the quarter. Compensation expense from restricted stock awards associated with our continuing operations was negligible and $0.4 million for the three and six months ended June 30, 2017, respectively, and $1.1 million and $0.9 million for the three and six months ended June 30, 2016, respectively. During the first quarter of 2016, 23,557 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.2 million for the quarter. As of June 30, 2017, total unrecognized compensation cost related to restricted common stock grants was approximately $1.1 million, which will be recognized over a weighted average period of 1.6 years.

A summary of the restricted stock activity for the six months ended June 30, 2017 is as follows:

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2016		242,824		$	26.34
Awards		101,237			5.18
Forfeitures		(19,185	)		86.78
Vested		(39,278	)		22.18
Restricted stock awards, as of June 30, 2017	$	285,598		$	15.35

12. COMMITMENTS AND CONTINGENCIES

Legal Reserves

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

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

For the quarter ended June 30, 2017, therewere no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, as supplemented by our Periodic Report on Form 10-Q for the period ended March 31, 2017.

Environmental

Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential

25

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, 2017, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

As of June 30, 2017, we have posted $46.3 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of June 30, 2017, 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, 2017, was approximately $0.2 million and $0.5 million, respectively, and $0.3 million and $0.6 million for the three and six months ended June 30, 2016, respectively. Lease commitments by year for each of the next five years are presented in the table below:

($ in Thousands)
2017	$	505
2018		565
2019		563
2020		422
2021		—
Thereafter		—
Total	$	2,055

Capacity Reservation

We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $9.1 million in 2017, $15.9 million in 2018, $15.9 million in 2019, $15.9 million in 2020, $15.9 million in 2021 and $78.3 million thereafter, assuming our average net revenue interest in the region of approximately 51%. Charges incurred for unutilized processing capacity with MarkWest during the three and six months ended June 30, 2017 were $1.7 million and $3.3 million, respectively, and $0.8 million and $1.4 million for the three and six months ended June 30, 2016, respectively.

Operational Commitments

We have contracted drilling rig services for one rig to support our Appalachian Basin operations. The minimum cost to retain the rig would require gross payments of approximately $1.4 million in 2017 and $1.8 million in 2018, which would be partially offset by other working interest owners, which vary from well to well.

Natural Gas Gathering, Processing and Sales Agreements

During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our 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 $391.5 million through 2029.

For the three and six months ended June 30, 2017, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $26.4 million and $52.7 million, respectively, and $21.8 million and $43.3 million for the three and six months ended June 30, 2016, 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, 2017, we incurred fees related to unutilized capacity commitments of approximately $0.7 million and $1.4 million, respectively, and $0.7 million and $1.0 million for the three and six months ended June 30, 2016, respectively.  The unutilized

26

commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

($ in Thousands)
2017	$	22,281
2018		46,241
2019		46,408
2020		45,123
2021		42,204
Thereafter		464,028
Total	$	666,285

Pennsylvania Impact Fee

In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:

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

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

All fees owed are due on April 1 of each year. For the three and six months ended June 30, 2017, we recorded expense of approximately $0.8 million and $1.6 million, respectively and $0.8 million and $1.3 million for the three and six months ended June 30, 2016, respectively.We record expenses related to the impact fees as Production and Lease Operating Expense. As of June 30, 2017, approximately $1.6 million was accrued for the 2017 impact fees.

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13. EARNINGS PER COMMON SHARE

Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the three and six months ended June 30, 2017, we excluded stock options to purchase 112,348 shares of our common stock, due to exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three and six months ended June 30, 2016, we excluded stock options to purchase 130,447 shares of our common stock, due to our Net Loss from Continuing Operations. For the three and six month periods ended June 30, 2017 and 2016, we excluded performance-based restricted stock of 43,124 shares and 71,715 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 the three and six months ended June 30, 2017, we excluded the assumed conversion of preferred stock equating to  221,502 common shares due to the antidilutive effect caused by the assumed conversion. During the three and six months ended June 30, 2016, we excluded the assumed conversion of preferred stock equating to 713,117 common shares and 227,057 common shares, respectively, due to our Net Loss from Continuing Operations. The following table sets forth the computation of basic and diluted earnings per common share:

(in thousands, except per share amounts)	Three Months Ended June 30,						Six Months Ended June 30,
Numerator:	2017			2016			2017			2016
Net Loss From Continuing Operations	$	(9,603	)	$	(52,911	)	$	(6,920	)	$	(105,562	)
Net Loss From Discontinued Operations		—			(1,683	)		—			(9,173	)
Less: Preferred Stock Dividends		(598	)		(1,723	)		(1,196	)		(3,828	)
Effect of Preferred Stock Conversions		—			72,316			—			72,316
Net Income (Loss) Attributable to Common Shareholders	$	(10,201	)	$	15,999		$	(8,116	)	$	(46,247	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		9,881			7,180			9,825			6,404
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		9,881			7,180			9,825			6,404
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic  —  Net Income (Loss) From Continuing Operations	$	(1.03	)	$	2.45		$	(0.83	)	$	(5.79	)
—  Net Loss From Discontinued Operations		—			(0.23	)		—			(1.43	)
—  Net Income (Loss) Attributable to Common Shareholders	$	(1.03	)	$	2.22		$	(0.83	)	$	(7.22	)
Diluted  —  Net Income (Loss) From Discontinued Operations	$	(1.03	)	$	2.45		$	(0.83	)	$	(5.79	)
—  Net Loss From Discontinued Operations		—			(0.23	)		—			(1.43	)
—  Net Income (Loss) Attributable to Common Shareholders	$	(1.03	)	$	2.22		$	(0.83	)	$	(7.22	)

14. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our natural gas operations. We did not make any capital contributions to RW Gathering during the first six months of 2017 and 2016. RW Gathering recorded net losses from continuing operations of $0.5 million and $1.0 million during the three and six months ended June 30, 2017, respectively, as compared to losses of $0.5 million and $1.0 million for the three and six months ended June 30, 2016, respectively.  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 months ended June 30, 2017 and 2016, we incurred approximately $0.1 million and $0.3 million, respectively, in compression expenses each year 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, 2017 and December 31, 2016, there were no receivables or payables due between RW Gathering and us.

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15. IMPAIRMENT EXPENSE

For the three and six months ended June 30, 2017, impairment expenses for continuing operations incurred were approximately $3.0 million and $4.6 million, respectively, and impairment expenses incurred for the three and six months ended June 30, 2016, were approximately $25.1 million and $35.8 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 six months ended June 30, 2017, included approximately $3.8 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 unconventional proved properties in our Butler County operations totaled approximately $0.8 million during the six months ended June 30, 2017.  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 properties could decline if commodity prices decline, which may result in additional impairment expense. As of June 30, 2017, we continued to carry the costs of undeveloped properties of approximately $205.7 million on our Consolidated Balance Sheet, which is related to the Marcellus and Utica Shale and for which we currently have development, trade or lease extension plans.

The expense incurred during the first six months of 2016 included proved properties of approximately $34.8 million in impairment related to undeveloped leases that expired or are expected to expire without being developed, the majority of which were in Butler County, Pennsylvania and Warrior North in Ohio.

16. EXPLORATION EXPENSE

For the three and six months ended June 30, 2017, exploration expenses for continuing operations incurred were approximately $0.1 million and $0.3 million, respectively, and approximately $0.8 million and $1.7 million for the three and six months ended June 30, 2016, respectively.  Approximately $0.2 million of the expense incurred in 2017 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals. Approximately $0.8 million of the expense incurred in 2016 was due to two exploratory wells that were abandoned at various stages, resulting in dry hole expense and the remaining 2016 expense of $0.9 million was due to geological and geophysical type expenditures.  

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of June 30, 2017, we had $600.3 million aggregate principal amount 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, 2017:

• Rex Energy I, LLC;

• Rex Energy Operating Corporation;

• Rex Energy IV, LLC;

• PennTex Resources Illinois, Inc.; and

• R.E. Gas Development, LLC.

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, 2017, 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, 2017 and December 31, 2016, the condensed consolidating statements of operations for the three and six months ended June 30, 2017 and 2016, and the condensed consolidating statements of cash flows for the six months ended June 30, 2017 and 2016.

29

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF JUNE 30, 2017

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	7,951		$	—		$	4,904		$	—		$	12,855
Accounts Receivable		23,755			—			7			—			23,762
Taxes Receivable		—			—			48			—			48
Short-Term Derivative Instruments		6,982			—			335			—			7,317
Inventory, Prepaid Expenses and Other		1,392			—			610			—			2,002
Total Current Assets		40,080			—			5,904			—			45,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		977,665			—			—			—			977,665
Unevaluated Oil and Gas Properties		205,691			—			—			—			205,691
Other Property and Equipment		22,309			—			—			—			22,309
Wells and Facilities in Progress		59,807			—			—			—			59,807
Pipelines		21,289			—			—			—			21,289
Total Property and Equipment		1,286,761			—			—			—			1,286,761
Less: Accumulated Depreciation, Depletion and Amortization		(434,483	)		—			—			—			(434,483	)
Net Property and Equipment		852,278			—			—			—			852,278
Other Assets		2,488			—			—			—			2,488
Intercompany Receivables		—			—			1,037,626			(1,037,626	)		—
Investment in Subsidiaries – Net		(2,484	)		—			(272,262	)		274,746			—
Long-Term Derivative Instruments		4,111			—			709			—			4,820
Total Assets	$	896,473		$	—		$	771,977		$	(762,880	)	$	905,570
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	46,235		$	—		$	—		$	—		$	46,235
Current Maturities of Long-Term Debt		834			—			—			—			834
Accrued Liabilities		30,025			421			2,345			—			32,791
Short-Term Derivative Instruments		6,563			—			—			—			6,563
Total Current Liabilities		83,657			421			2,345			—			86,423
Long-Term Derivative Instruments		9,450			—			—			—			9,450
Term Loans, Net		—			—			136,163			—			136,163
Senior Notes, Net		—			—			648,820			—			648,820
Other Long-Term Debt		3,627			—			—			—			3,627
Other Deposits and Liabilities		7,731			—			—			—			7,731
Future Abandonment Cost		9,658			—			—			—			9,658
Intercompany Payables		1,033,962			3,664			—			(1,037,626	)		—
Total Liabilities		1,148,085			4,085			787,328			(1,037,626	)		901,872
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			10			—			10
Additional Paid-In Capital		177,144			—			651,659			(177,144	)		651,659
Accumulated Deficit		(428,756	)		(4,085	)		(667,021	)		451,890			(647,972	)
Total Stockholders’ Equity		(251,612	)		(4,085	)		(15,351	)		274,746			3,698
Total Liabilities and Stockholders’ Equity	$	896,473		$	—		$	771,977		$	(762,880	)	$	905,570

30

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED JUNE 30, 2017

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	47,457		$	—		$	—		$	—		$	47,457
Other Operating Revenue		5			—			—			—			5
TOTAL OPERATING REVENUE		47,462			—			—			—			47,462
OPERATING EXPENSES
Production and Lease Operating Expense		29,374			—			—			—			29,374
General and Administrative Expense		3,771			—			523			—			4,294
Gain on Disposal of Assets		(124	)		—			—			—			(124	)
Impairment Expense		3,032			—			—			—			3,032
Exploration Expense		99			—			—			—			99
Depreciation, Depletion, Amortization and Accretion		15,501			—			—			—			15,501
Other Operating (Income) Expense		(99	)		1			—			—			(98	)
TOTAL OPERATING EXPENSES		51,554			1			523			—			52,078
LOSS FROM OPERATIONS		(4,092	)		(1	)		(523	)		—			(4,616	)
OTHER INCOME (EXPENSE)
Interest Expense		(442	)		—			(11,680	)		—			(12,122	)
Gain (Loss) on Derivatives, Net		10,861			—			(475	)		—			10,386
Other Income		20			—			—			—			20
Loss on Extinguishments of Debt		—			—			(3,271	)		—			(3,271	)
(Loss) Income From Equity in Consolidated Subsidiaries		(1	)		—			6,346			(6,345	)		—
TOTAL OTHER INCOME (EXPENSE)		10,438			—			(9,080	)		(6,345	)		(4,987	)
INCOME BEFORE INCOME TAX		6,346			(1	)		(9,603	)		(6,345	)		(9,603	)
Income Tax Expense		—			—			—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	6,346		$	(1	)	$	(9,603	)	$	(6,345	)	$	(9,603	)
Preferred Stock Dividends		—			—			(598	)		—			(598	)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	6,346		$	(1	)	$	(10,201	)	$	(6,345	)	$	(10,201	)

31

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2017

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	99,522		$	—		$	—		$	—		$	99,522
Other Operating Revenue		11			—			—			—			11
TOTAL OPERATING REVENUE		99,533			—			—			—			99,533
OPERATING EXPENSES
Production and Lease Operating Expense		58,308			—			—			—			58,308
General and Administrative Expense		8,232			—			596			—			8,828
Gain on Disposal of Assets		(1,959	)		—			—			—			(1,959	)
Impairment Expense		4,577			—			—			—			4,577
Exploration Expense		319			—			—			—			319
Depreciation, Depletion, Amortization and Accretion		30,969			—			—			—			30,969
Other Operating (Income) Expense		(119	)		1			—			—			(118	)
TOTAL OPERATING EXPENSES		100,327			1			596			—			100,924
LOSS FROM OPERATIONS		(794	)		(1	)		(596	)		—			(1,391	)
OTHER INCOME (EXPENSE)
Interest Expense		(809	)		—			(20,457	)		—			(21,266	)
Gain (Loss) on Derivatives, Net		20,659			—			(1,893	)		—			18,766
Other Expense		(7	)		—			—			—			(7	)
Loss on Extinguishments of Debt		—			—			(3,022	)		—			(3,022	)
(Loss) Income from Equity in Consolidated Subsidiaries		(1	)					19,048			(19,047	)		—
TOTAL OTHER INCOME (EXPENSE)		19,842			—			(6,324	)		(19,047	)		(5,529	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME    TAX		19,048			(1	)		(6,920	)		(19,047	)		(6,920	)
Income Tax Expense		—			—			—			—			—
INCOME (LOSS) FROM CONTINUING OPERATIONS		19,048			(1	)		(6,920	)		(19,047	)		(6,920	)
Income (Loss) From Discontinued Operations, Net of Income Tax		—			—			—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	19,048		$	(1	)	$	(6,920	)	$	(19,047	)	$	(6,920	)
Preferred Stock Dividends		—			—			(1,196	)		—			(1,196)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	19,048		$	(1	)	$	(8,116	)	$	(19,047	)	$	(8,116)

32

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2017

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations				Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	19,048		$	(1	)	$	(6,920	)	$	(19,047	)		$	(6,920	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided       by Operating Activities
Depreciation, Depletion, Amortization and Accretion		30,969			—			—			—				30,969
(Gain) Loss on Derivatives		(20,659	)		—			1,893			—				(18,766	)
Cash Settlements of Derivatives		(5,525	)		—			—			—				(5,525	)
Non-cash Dry Hole Expense		13			—			—			—				13
Equity-based Compensation Expense		—			—			571			—				571
Gain on Disposal of Assets		(1,959	)		—			—			—				(1,959	)
Loss on Extinguishments Debt		—			—			3,022			—				3,022
Non-cash Interest Expense related to Debt Restructurings     and Exchanges		—			—			12,431			—				12,431
Impairment Expense		4,577			—			—			—				4,577
Other Non-cash Income		41			—			—			—				41
Changes in operating assets and liabilities
Accounts Receivable		7,232			—			(3	)		—				7,229
Taxes Receivable		—			—			163			—				163
Inventory, Prepaid Expenses and Other Assets		638			—			(586	)		—				52
Accounts Payable and Accrued Liabilities		(1,484	)		—			—			—				(1,484	)
Other Assets and Liabilities		(1,104	)		—			—			—				(1,104	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		31,787			(1	)		10,571			(19,047	)	��		23,310
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		4,063			1			(23,111	)		19,047				—
Proceeds from the Sale of Oil and Gas Properties, Prospects      and Other Assets		24,513			—			—			—				24,513
Acquisitions of Undeveloped Acreage		(1,783	)		—			—			—				(1,783	)
Capital Expenditures for Development of Oil and Gas      Properties and Equipment		(54,004	)		—			—			—				(54,004	)
NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES		(27,211	)		1			(23,111	)		19,047				(31,274	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit		—			—			171,000			—				171,000
Repayments of Long-Term Debt and Line of Credit		—			—			(145,170	)		—				(145,170	)
Repayments of Loans and Other Long-Term Debt		(319	)		—			—			—				(319	)
Debt Issuance Costs		—			—			(7,791	)		—				(7,791	)
Payment of Preferred Dividends in Arrears		—			—			(598	)		—				(598	)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(319	)		—			17,441			—				17,122
NET INCREASE IN CASH		4,257			—			4,901			—				9,158
CASH – BEGINNING		3,694			—			3			—				3,697
CASH - ENDING	$	7,951		$	—		$	4,904		$	—			$	12,855

33

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF DECEMBER 31, 2016

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,694		$	—		$	3		$	—		$	3,697
Accounts Receivable		22,609			—			2,839			—			25,448
Taxes Receivable		—			—			211			—			211
Short-Term Derivative Instruments		650			—			1,223			—			1,873
Inventory, Prepaid Expenses and Other		2,521			—			25			—			2,546
Total Current Assets		29,474			—			4,301			—			33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,053,461			—			—			—			1,053,461
Unevaluated Oil and Gas Properties		215,794			—			—			—			215,794
Other Property and Equipment		21,401			—			—			—			21,401
Wells and Facilities in Progress		21,964			—			—			—			21,964
Pipelines		18,029			—			—			—			18,029
Total Property and Equipment		1,330,649			—			—			—			1,330,649
Less: Accumulated Depreciation, Depletion and Amortization		(475,205	)		—			—			—			(475,205	)
Net Property and Equipment		855,444			—			—			—			855,444
Other Assets		2,492			—			—			—			2,492
Intercompany Receivables		—			—			1,035,713			(1,035,713	)		—
Investment in Subsidiaries – Net		(2,388	)		—			(127,974	)		130,362			—
Long-Term Derivative Instruments		500			—			1,712			—			2,212
Total Assets	$	885,522		$	—		$	913,752		$	(905,351	)	$	893,923
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	40,712		$	—		$	—		$	—		$	40,712
Current Maturities of Long-Term Debt		764			—			—			—			764
Accrued Liabilities		32,328			421			4,458			—			37,207
Short-Term Derivative Instruments		25,025			—			—			—			25,025
Total Current Liabilities		98,829			421			4,458			—			103,708
Long-Term Derivative Instruments		7,227			—			—			—			7,227
Senior Secured Line of Credit, Net		—			—			113,785			—			113,785
Term Loans. Net		—			—			—			—			—
Senior Notes, Net		—			—			638,161			—			638,161
Other Long-Term Debt		3,409			—			—			—			3,409
Other Deposits and Liabilities		8,671			—			—			—			8,671
Future Abandonment Cost		8,736			—			—			—			8,736
Intercompany Payables		1,032,050			3,663			—			(1,035,713	)		—
Total Liabilities		1,158,922			4,084			756,404			(1,035,713	)		883,697
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			10			—			10
Additional Paid-In Capital		177,144			—			650,669			(177,144	)		650,669
Accumulated Deficit		(450,544	)		(4,084	)		(493,332	)		307,506			(640,454	)
Total Stockholders’ Equity		(273,400	)		(4,084	)		157,348			130,362			10,226
Total Liabilities and Stockholders’ Equity	$	885,522		$	—		$	913,752		$	(905,351	)	$	893,923

34

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED JUNE 30, 2016  

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	31,271		$	—		$	—		$	—	$	31,271
Other Operating 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
Loss 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
(Loss) Income 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 Benefit (Expense)		473			—			(80	)		—		393
INCOME (LOSS) FROM CONTINUING OPERATIONS		(63,710	)		51			(54,593	)		65,341		(52,911	)
Loss From Discontinued Operations, Net of Income Tax		(1,629	)		(54	)		—			—		(1,683	)
NET INCOME (LOSS)		(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

35

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2016  

($ in Thousands)

	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	)

36

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2016

($ in Thousands)

	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 Loss to Net Cash Provided by    Operating Activities
Depreciation, Depletion, Amortization and Accretion		36,293			52			—			—			36,345
Loss on Derivatives, Net		25,120			—			—			—			25,120
Cash Settlements of Derivatives		30,340			—			—			—			30,340
Dry Hole Expense		870			—			—			—			870
Equity-based Compensation Expense		—			—			1,305			—			1,305
Gain on Disposal of Assets		(4,338	)		—			—			—			(4,338	)
Amortization of net Bond Discount and Deferred Debt Issuance Costs		—			—			538			—			538
Non-cash Interest Expense related to Debt Restructurings     and Exchanges		—			—			8,126			—			8,126
Gain on Extinguishment of Debt		—			—			(23,757	)		—			(23,757	)
Impairment Expense		39,330			(7	)		39,323			(39,323	)		39,323
Other Non-cash (Income) Expense		(100	)		—			231			—			131
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 (USED IN) PROVIDED BY 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 (USED IN) PROVIDED BY 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

37

18. SUBSEQUENT EVENTS

Marketing Agreement with BP Energy Company

On August 1, 2017, we entered into a comprehensive marketing arrangement with BP Structured Products (“BP”) pursuant to which BP will market the majority of our liquid C3+ products stream and support several other marketing initiatives out of our Butler and Warrior North operating areas.  

Beginning January 1, 2018, BP will purchase the majority of our C3+ products stream at a fixed price differential to Mt. Bellevue for a four year term.  The fixed priced differential compares favorably to 2016 and currently projected 2017 differentials, is expected to eliminate the wide fluctuations between summer and winter pricing during the term, and is expected to allow more flexibility in the timing for placement of wells into sales.  As a result of the new marketing arrangement, we were able to reduce one of our firm transportation credit support obligations by approximately $14.1 million, which will in turn increase our available borrowing base under the Delayed Draw Term Facility by a similar amount.  As part of the broader marketing initiatives, BP will also market a portion of our Warrior North gas at an improved differential to the current pricing.

Sale of Salineville Waterline

In July 2018, we entered into an agreement with Keystone Clearwater Solutions (“Keystone”) to sell a permanent waterline in Ohio, which provides fresh water for completions operations in our Warrior North operated area, to Keystone. Keystone will own and operate the waterline. In conjunction with the sale, we entered into a leasing arrangement with Keystone to maintain first right of refusal on available water. The purchase price of the waterline was approximately $7.0 million. We intend to account for this transaction as a sale-leaseback arrangement and, pursuant to ASC 360, continue to hold this asset as held and used as of June 30, 2017.

38

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

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2016 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

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

Overview of Our Business

We are an independent natural gas, NGL and condensate company operating in the Appalachian Basin, where we are focused on our Marcellus Shale, Utica Shale and Upper Devonian 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 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.

In June 2016, we entered into a purchase and sale agreement to divest all of our assets in the Illinois Basin. As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale” and our assets and operations of the Illinois Basin are reported as Discontinued Operations. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016 in exchange for approximately $40.5 million in proceeds.

2017 Activity

During the three and six months ended June 30, 2017, we produced 16,112 MMcfe and 31,716 MMcfe, respectively. Overall, our production for the three and six months ended June 30, 2017 averaged 177 MMcfe per day and 175 MMcfe per day, respectively. As of June 30, 2017, we had 13.0 gross (7.7 net) wells drilled and awaiting completion. We had no wells resting or awaiting pipeline connection as of June 30, 2017. Our drilling and completion activity for the period indicated is set forth in the table below.

Three and Six Months Ended June 30, 2017 and 2016

Three Months Ended June 30, 2017
Wells Drilled				Wells Completed				Wells Placed In Service
Gross		Net		Gross		Net		Gross		Net
	6.0		4.8		6.0		3.1		4.0		1.4
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
Six Months Ended June 30, 2017
Wells Drilled				Wells Completed				Wells Placed In Service
Gross		Net		Gross		Net		Gross		Net
	14.0		8.6		10.0		4.5		4.0		1.4
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

39

Commodity Prices

Our development plans are sensitive to current and projected commodity prices which have been and are expected to continue to be volatile. Our realized price, before derivative settlements, for natural gas during the three and six months ended June 30, 2017, averaged approximately $2.94 per Mcf, and $3.05 Mcf, respectively, as compared to $1.42 per Mcf and $1.39 Mcf for the three and six months ended June 30, 2016, respectively. Our realized price, before derivative settlements, for condensate during the three and six months ended June 30, 2017, averaged approximately $42.35 per barrel and $44.25 per barrel, respectively, as compared to $37.20 per barrel and $31.91 per barrel for the three and six months ended June 30, 2016, respectively. Our realized price, before derivative settlements, for C3+ NGLs during the three and six months ended June 30, 2017 averaged approximately $23.03 per barrel and $26.86 per barrel, respectively, as compared to $15.49 per barrel and $13.87 per barrel for the three and six months ended June 30, 2016, respectively. Our realized price, before derivative settlements, for ethane during the three and six months ended June 30, 2017, averaged approximately $9.96 per barrel and $9.74 per barrel, respectively, and $7.49 per barrel and $6.84 per barrel as compared for the three and six months ended June 30, 2016, respectively.  

For the three and six months ended June 30, 2017, we recorded impairment expense of approximately $3.0 million and $4.6 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, 2017, approximately $473.6 million, or 83.8%, 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 $91.5 million as June 30, 2017.

Debt for Equity Exchanges

During the first six months of 2017, we entered into privately negotiated debt-to-equity exchanges with certain holders of our Senior Notes in exchange for unrestricted shares of our common stock.  These exchanges resulted in the retirement of approximately $0.9 million of our outstanding Senior Notes, in exchange for the issuance of 83,626 shares of unrestricted common stock.  The exchanged notes were subsequently cancelled, resulting in a gain to the Company of approximately $0.4 million, included as a component of Gain (Loss) on Extinguishments of Debt in our Consolidated Statement of Operations for the six months ended June 30, 2017.

Benefit Street Partners, LLC Joint Venture

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 agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and 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 paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of June 30, 2017. BSP has paid approximately $103.0 million for its interest in elected wells as of June 30, 2017. 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 it participates. As of June 30, 2017, 34 of the 45 committed wells were in line and producing, and four were completed waiting to go in line, and seven wells were drilled and awaiting completion.

40

Results of Continuing Operations

The following table sets forth summary information regarding NGL, condensate and natural gas production and product prices for the three and six months ended June 30, 2017 and 2016:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2017		2016		2017		2016
Production:
Natural Gas (Mcf)		9,889,888		11,327,101		19,801,630		22,631,620
Condensate (Bbls)		70,687		90,565		144,927		153,628
C3+ NGLs (Bbls)		439,441		507,990		861,146		997,744
Ethane (Bbls)		526,893		532,928		979,580		971,140
Total (Mcfe)(a)		16,112,014		18,115,999		31,715,548		35,366,692
Average daily production:
Natural Gas (Mcf)		108,680		124,474		109,401		124,350
Condensate (Bbls)		777		995		801		844
C3+ NGLs (Bbls)		4,829		5,582		4,758		5,482
Ethane (Bbls)		5,790		5,856		5,412		5,336
Total (Mcfe)(a)		177,055		199,077		175,224		194,322
Average sales price(b):
Natural Gas (per Mcf)	$	2.94	$	1.42	$	3.05	$	1.39
Condensate (per Bbl)	$	42.35	$	37.20	$	44.25	$	31.91
C3+ NGLs (per Bbl)	$	23.03	$	15.49	$	26.86	$	13.87
Ethane (per Bbl)	$	9.96	$	7.49	$	9.74	$	6.84
Total (per Mcfe)(a)	$	2.95	$	1.73	$	3.14	$	1.61
Average NYMEX prices(c):
Oil (per Bbl)	$	48.28	$	45.59	$	50.10	$	39.52
Natural Gas (per Mcf)	$	3.05	$	2.24	$	3.02	$	2.12

(a) Condensate, Ethane and C3+ NGLs are converted at the rate of one barrel of oil equivalent (“BOE”) to six Mcfe.

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

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

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, 2017 and 2016:

	Production and Revenue by Product
	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2017		2016		2017		2016
Revenue – Natural Gas(a)	$	29,097,041	$	16,044,170	$	60,441,673	$	31,559,846
Volumes (Mcf)		9,889,888		11,327,101		19,801,630		22,631,620
Average Price	$	2.94	$	1.42	$	3.05	$	1.39
Revenue – Condensate (a)	$	2,993,340	$	3,368,581	$	6,413,513	$	4,902,336
Volumes (Bbl)		70,687		90,565		144,927		153,628
Average Price	$	42.35	$	37.20	$	44.25	$	31.91
Revenue – C3+ NGLs(a)	$	10,119,239	$	7,867,132	$	23,126,667	$	13,842,338
Volumes (Bbl)		439,441		507,990		861,146		997,744
Average Price	$	23.03	$	15.49	$	26.86	$	13.87
Revenue – Ethane(a)	$	5,247,189	$	3,990,742	$	9,540,190	$	6,639,427
Volumes (Bbl)		526,893		532,928		979,580		971,140
Average Price	$	9.96	$	7.49	$	9.74	$	6.84
Average Production Cost per Mcfe(b)	$	1.82	$	1.39	$	1.84	$	1.40

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

(b) Excludes ad valorem and severance taxes.

41

General Overview

Operating revenue for the three and six months ended June 30, 2017 increased 51.8% and 74.8% when compared to the same periods in 2016, respectively. The increase in operating revenue for the three and six months ended June 30, 2017 can be primarily attributed to higher natural gas, condensate and NGL prices, offset partially by lower production volumes. Our production decreased to 16,112 MMcfe for the three month period ended June 30, 2017, from 18,116 MMcfe for the three month period ended June 30, 2016, approximately 11.1%. For the six months ended June 30, 2017, our production decreased 10.3% to 31,716 MMcfe from the six months ended June 30, 2016.  For the three month period ended June 30, 2017, our realized sales price for natural gas increased to $2.94 per Mcf from $1.42 per Mcf, condensate increased to $42.35 per barrel from $37.20 per barrel, C3+ NGLs increased to $23.03 per barrel from $15.49 per barrel, and ethane increased to $9.96 per barrel from $7.49 per barrel, respectively, when compared to the same period in 2016.  For the six months ended June 30, 2017, our realized sales price for natural gas increased to $3.05 per Mcf from $1.39 per Mcf, condensate increased to $44.25 per barrel from $31.91 per barrel, C3+ NGLs increased to $26.86 per barrel from $13.87 per barrel, and ethane increased to $9.74 per barrel from $6.84 per barrel, respectively, when compared to the same period in 2016.

Operating expenses decreased $15.1 million and $24.4 million, respectively, for the three and six months ended June 30, 2017, as compared to the same periods in 2016. 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, and lower G&A expenses, net of higher Lease Operating Expenses. 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 prices realized during the three and six months ended June 30, 2016.

Comparison of the Three Months Ended June 30, 2017 to the Three Months Ended June 30, 2016

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the three-month periods ended June 30, 2017 and 2016 is summarized in the following table:

	For the Three Months Ended June 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2017			2016		Change			%
Gas sales revenue	$	29,097		$	16,044	$	13,053			81.4	%
Gas derivatives realized(a)	$	(1,594	)	$	14,857	$	(16,451	)		(110.7	)%
Total gas revenue and derivatives realized	$	27,503		$	30,901	$	(3,398	)		(11.0	)%
Condensate sales revenue	$	2,993		$	3,369	$	(376	)		(11.2	)%
Oil and condensate derivatives realized(a)	$	141		$	310	$	(169	)		(54.5	)%
Total condensate revenue and derivatives realized	$	3,134		$	3,679	$	(545	)		(14.8	)%
C3+ NGL revenue	$	10,119		$	7,867	$	2,252			28.6	%
C3+ NGL derivatives realized(a)	$	(616	)	$	2,255	$	(2,871	)		(127.3	)%
Total C3+ NGL revenue	$	9,503		$	10,122	$	(619	)		(6.1	)%
Ethane revenue	$	5,247		$	3,991	$	1,256			31.5	%
Ethane derivatives realized(a)	$	(12	)	$	—	$	(12	)		100.0	%
Total Ethane revenue	$	5,235		$	3,991	$	1,244			31.2	%
Consolidated sales	$	47,456		$	31,271	$	16,185			51.8	%
Consolidated derivatives realized(a)	$	(2,081	)	$	17,422	$	(19,503	)		(111.9	)%
Total NGL, condensate and gas revenue and derivatives realized	$	45,375		$	48,693	$	(3,318	)		(6.8	)%
Total Mcfe Production		16,112,014			18,115,999		(2,003,985	)		(11.1	)%
Average Realized Price per Mcfe	$	2.82		$	2.69	$	0.13			4.8	%

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

Average realized price received for natural gas, condensate and NGLs during the second quarter of 2017, after the effect of derivative activities, was $2.82 per Mcfe, an increase of 4.8%, or $0.13 per Mcfe, from the same period in 2016. This increase was primarily due to an increase in commodity prices during the quarter, partially offset by cash-settled losses on derivatives. The average price for natural gas, after the effect of derivative activities, increased 1.9%, or $0.05 per Mcf, to $2.78 per Mcf. The average price for condensate, after the effect of derivative activities, increased 9.1%, or $3.71 per barrel, to $44.35 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 8.5%, or $1.70 per barrel, to $21.62 per barrel. The average price for ethane, after the effect of derivative activities, increased 32.7%, or $2.45 per barrel, to $9.93 per barrel. Our derivative activities effectively decreased net realized prices by $0.13 per Mcfe in the second quarter of 2017 and increased net realized prices by $0.96 per Mcfe in the second quarter of 2016.

Our realized sales price for natural gas was lower than the average Henry Hub NYMEX pricing by approximately $0.11 per Mcf during the second quarter of 2017, 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

42

of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast, including transportation of 100,000 Mcf per day to the Gulf Coast that began during the fourth quarter of 2016.

Production volumes in the second quarter of 2017 decreased 11.1%, or 2004.0 MMcfe, from the second quarter of 2016 primarily due to the sale of our Warrior South assets during first quarter of 2017. Natural gas production decreased approximately 12.7%, condensate production decreased approximately 21.9%, C3+ NGL production decreased approximately 13.5% and our ethane production decreased approximately 1.1%.

Overall, our production for the second quarter of 2017 averaged 177,055 Mcfe per day, of which 61.4% was attributable to natural gas, 2.6% to condensate, 16.4% to C3+ NGLs and 19.64 was a result of ethane production.

Statements of Operations for the three months ended June 30, 2017 and 2016 are as follows:

	For the Three Months Ended June 30,
($ in Thousands)	2017			2016			Change			%
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	47,457		$	31,271		$	16,186			51.8	%
Other Operating Revenue (Expense)		5			(6	)		11			(183.3	)%
TOTAL OPERATING REVENUE		47,462			31,265			16,197			51.8	%
OPERATING EXPENSES
Production and Lease Operating Expense		29,374			25,221			4,153			16.5	%
General and Administrative Expense		4,294			4,837			(543	)		(11.2	)%
Gain on Disposal of Assets		(124	)		(4,307	)		4,183			(97.1	)%
Impairment Expense		3,032			25,139			(22,107	)		(87.9	)%
Exploration Expense		99			803			(704	)		(87.7	)%
Depreciation, Depletion, Amortization and Accretion		15,501			14,750			751			5.1	%
Other Operating (Income) Expense		(98	)		704			(802	)		(113.9	)%
TOTAL OPERATING EXPENSES		52,078			67,147			(15,069	)		(22.4	)%
LOSS FROM OPERATIONS		(4,616	)		(35,882	)		31,266			(87.1	)%
OTHER INCOME (EXPENSE)
Interest Expense		(12,122	)		(11,439	)		(683	)		6.0	%
Gain (Loss) on Derivatives, Net		10,386			(29,169	)		39,555			(135.6	)%
Other Income		20			12			8			66.7	%
Debt Exchange Expense		—			(533	)		533			(100.0	)%
(Loss) Gain on Extinguishment of Debt		(3,271	)		23,707			(26,978	)		(113.8	)%
TOTAL OTHER EXPENSE		(4,987	)		(17,422	)		12,435			(71.4	)%
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(9,603	)		(53,304	)		43,701			(82.0	)%
Income Tax Benefit		—			393			(393	)		(100.0	)%
NET LOSS FROM CONTINUING OPERATIONS		(9,603	)		(52,911	)		43,308			(81.9	)%
Loss From Discontinued Operations, Net of Income Taxes		—			(1,683	)		1,683			(100.0	)%
NET LOSS	$	(9,603	)	$	(54,594	)	$	44,991			(82.4	)%

Production and Lease Operating Expense increased approximately $4.2 million, or 16.5%, in the second quarter of 2017 from the same period in 2016. 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 89.9% of our total Production and Lease Operating Expense in the second quarter of 2017, as compared to 86.5% from the same period in 2016. 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 were $1.82 and $1.39 per Mcfe for the three months ended June 30, 2017 and 2016, respectively. The increase on a per unit basis is related to the commencement of our Gulf Coast transportation agreement.

G&A Expense for the second quarter of 2017 decreased approximately $0.5 million, or 11.2%, to $4.3 million from the same period in 2016. The decrease was mostly due to the forfeiture for restricted stock, which was approximately $0.3 million.

Impairment Expense for the second quarter of 2017 was approximately $3.0 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 2017 included $3.0 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 $0.1 million during the second quarter of 2017. The impairments were

43

identified through an analysis of market conditions and future development plans related to these properties that were in existence as of June 30, 2017, 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 2017 was approximately $0.1 million, as compared to $0.8 million for same period in 2016. The expense incurred in 2017 was mostly due to geological and geophysical type expenditures. Approximately $0.8 million of the expense incurred in 2016 was due to geological and geophysical type expenditures. 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 2017 increased approximately $0.7 million, or 5.1%, from $14.8 million for the same period in 2016. Contributing to the increase in DD&A expense was an increase in depreciable asset values due to the completion of waterline facilities compared to the same period in 2016 and an increase in accretion expense related to the abandonment of three work in progress unconventional wells during 2017 compared to the same period in 2016.

Other Operating Expense for the second quarter of 2017 decreased approximately $0.8 million from $0.7 million for the same period in 2016. The expense in 2016 was primarily related to a firm transportation contract associated with an area west of our core assets in Butler County, Pennsylvania.

Interest Expense for the second quarter of 2017 was approximately $12.1 million as compared to $11.4 million for the same period in 2016. The increase in interest expense is primarily due to interest charges incurred on the available but undrawn borrowing base of the Term Loan established in April, 2017. The increase is partially offset by a decrease in semi-annual bond interest payments due to our Senior Note exchanges. We discuss our Term Loan and Senior Notes in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain (Loss) on Derivatives, net included a gain of approximately $10.4 million for the second quarter of 2017 as compared to a loss of $29.2 million for the same period in 2016. The gain recorded for the second quarter of 2017 included cash payments for commodity derivatives of $2.1 million while the loss incurred in the second quarter of 2016 included cash receipts of approximately $17.3 million for commodity 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 2017 and 2018, 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.

Gain (Loss) on Extinguishments of Debt for the second quarter of 2017 totaled a loss of approximately $3.3 million.  The loss in 2017 reflects the write-off of approximately $3.5 million of unamortized debt issuance costs related to the Senior Credit Facility retired in April 2017, offset by approximately $0.2 million in gains from debt to equity exchanges completed in the second quarter of 2017. Gain on extinguishments of debt for the second quarter of 2016 totaled approximately $23.7 million, resulting from debt to equity exchanges with certain holders of our Senior Notes. We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Expense for continuing operations for the second quarter of 2017 was $0.0 million, or 0.0% of pretax income, due to the full valuation allowances we maintain against our net deferred tax assets.

For the second quarter of 2016, income tax benefit was $0.4 million. Our estimated annual effective tax rate for 2016 differed from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets coupled with recognizing tax benefits in continuing operations for the effect of taxable income generated by our discontinued operations. To a lesser extent, the annual effective rate is also influenced by alternative minimum tax with no corresponding deferred tax benefit due to the full valuation allowance, and state taxes in certain tax paying jurisdictions.  The Company’s alternative minimum tax due for 2016 was driven primarily by cancellation of debt income of $543.2 million related to the Senior Note exchanges.   

Net Income (Loss) Attributable to Rex Energy for the second quarter of 2017 was a loss of approximately $9.6 million, as compared to a loss of $54.6 million for the same period in 2016 as a result of factors discussed above.

44

Comparison of the Six Months Ended June 30, 2017 to the Six Months Ended June 30, 2016

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the six-month periods ended June 30, 2017 and 2016 is summarized in the following table:

	For the Six Months Ended June 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2017			2016		Change			%
Gas sales revenue	$	60,442		$	31,560	$	28,882			91.5	%
Gas derivatives realized(a)	$	(2,766	)	$	23,080	$	(25,846	)		(112.0	)%
Total gas revenue and derivatives realized	$	57,676		$	54,640	$	3,036			5.6	%
Condensate sales revenue	$	6,414		$	4,902	$	1,512			30.8	%
Oil and condensate derivatives realized(a)	$	146		$	2,098	$	(1,952	)		(93.0	)%
Total condensate revenue and derivatives realized	$	6,560		$	7,000	$	(440	)		(6.3	)%
C3+ NGL revenue	$	23,127		$	13,843	$	9,284			67.1	%
C3+ NGL derivatives realized(a)	$	(3,001	)	$	5,211	$	(8,212	)		(157.6	)%
Total C3+ NGL revenue	$	20,126		$	19,054	$	1,072			5.6	%
Ethane revenue	$	9,540		$	6,639	$	2,901			43.7	%
Ethane derivatives realized(a)	$	96		$	144	$	(48	)		(33.3	)%
Total Ethane revenue	$	9,636		$	6,783	$	2,853			42.1	%
Consolidated sales	$	99,523		$	56,944	$	42,579			74.8	%
Consolidated derivatives realized(a)	$	(5,525	)	$	30,533	$	(36,058	)		(118.1	)%
Total NGL, condensate and gas revenue and derivatives realized	$	93,998		$	87,477	$	6,521			7.5	%
Total Mcfe Production		31,715,548			35,366,692		(3,651,144	)		(10.3	)%
Average Realized Price per Mcfe	$	2.96		$	2.47	$	0.49			19.8	%

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

Average realized price received for natural gas, condensate and NGLs during the first half of 2017 after the effect of derivative activities, was $2.96 per Mcfe, an increase of 19.8%, or $0.49 per Mcfe, from the same period in 2016. This increase was primarily due to an increase in commodity prices during the first half of the year, partially offset by cash-settled losses on derivatives. The average price for natural gas, after the effect of derivative activities, increased 20.6%, or $0.50 per Mcf, to $2.91per Mcf. The average price for condensate, after the effect of derivative activities, decreased 0.7%, or $0.30 per barrel, to $45.26 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 22.4%, or $4.27 per barrel, to $23.37 per barrel. The average price for ethane, after the effect of derivative activities, increased 40.8%, or $2.85 per barrel, to $9.84 per barrel. Our derivative activities effectively decreased net realized prices by $0.17 per Mcfe in the first half of 2017 and increased net realized prices by $0.86 per Mcfe in the first half of 2016.

Our realized sales price for natural gas was higher than the average Henry Hub NYMEX pricing by approximately $0.03 per Mcf during the first half of 2017, 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, including transportation of 100,000 Mcf per day to the Gulf Coast that began during the fourth quarter of 2016.

Production volumes in the first six months of 2017 decreased 10.3%, or 3,651.1 MMcfe, from the first six months of 2016, primarily due to the sale of our Warrior South assets during first quarter of 2017. Natural gas production decreased approximately 14.3%, condensate production decreased approximately 6.0%, C3+ NGL production decreased approximately 15.9% and our ethane production increased approximately 0.9%.

Overall, our production for the first six months of 2017 averaged 175,224 Mcfe per day, of which 62.4% was attributable to natural gas, 2.7% to condensate, 16.3% to C3+ NGLs and 18.5% was a result of ethane production.

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Statements of Operations for the six-month periods ended June 30, 2017 and 2016 are as follows:

	For the Six Months Ended June 30,
($ in Thousands)	2017			2016			Change			%
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	99,522		$	56,944		$	42,578			74.8	%
Other Operating Revenue		11			7			4			57.1	%
TOTAL OPERATING REVENUE		99,533			56,951			42,582			74.8	%
OPERATING EXPENSES
Production and Lease Operating Expense		58,308			49,672			8,636			17.4	%
General and Administrative Expense		8,828			10,121			(1,293	)		(12.8	)%
Gain on Disposal of Assets		(1,959	)		(4,295	)		2,336			(54.4	)%
Impairment Expense		4,577			35,780			(31,203	)		(87.2	)%
Exploration Expense		319			1,738			(1,419	)		(81.6	)%
Depreciation, Depletion, Amortization and Accretion		30,969			31,262			(293	)		(0.9	)%
Other Operating (Income) Expense		(118	)		1,030			(1,148	)		(111.5	)%
TOTAL OPERATING EXPENSES		100,924			125,308			(24,384	)		(19.5	)%
LOSS FROM OPERATIONS		(1,391	)		(68,357	)		66,966			(98.0	)%
OTHER INCOME (EXPENSE)
Interest Expense		(21,266	)		(24,469	)		3,203			(13.1	)%
Gain (Loss) on Derivatives, Net		18,766			(25,120	)		43,886			(174.7	)%
Other (Expense) Income		(7	)		12			(19	)		(158.3	)%
Debt Exchange Expense		—			(9,014	)		9,014			(100.0	)%
(Loss) Gain on Extinguishment of Debt		(3,022	)		23,707			(26,729	)		(112.7	)%
TOTAL OTHER EXPENSE		(5,529	)		(34,884	)		29,355			(84.2	)%
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(6,920	)		(103,241	)		96,321			(93.3	)%
Income Tax Expense		—			(2,321	)		2,321			(100.0	)%
LOSS FROM CONTINUING OPERATIONS		(6,920	)		(105,562	)		98,642			(93.4	)%
Loss From Discontinued Operations, Net of Income Taxes		—			(9,173	)		9,173			(100.0	)%
NET LOSS		(6,920	)		(114,735	)		107,815			(94.0	)%

Production and Lease Operating Expense increased approximately $8.6 million, or 17.4%, in the first half of 2017 from the same period in 2016. 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 90.3% of our total Production and Lease Operating Expense in the first half of 2017, as compared to 87.1% from the same period in 2016. 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 were $1.84 and $1.40 per Mcfe for the six months ended June 30, 2017 and 2016, respectively. The increase on a per unit basis is related to the commencement of our Gulf Coast transportation agreement.

G&A Expense for the first half of 2017 decreased approximately $1.3 million, or 12.8%, to $8.8 million from the same period in 2016. The decrease was mostly due to a decrease in transactional fees associated with the BSP transaction of $0.4 million during first half of 2017 as compared to $1.4 million during same period in 2016.  Also contributing to the decrease in G&A was the forfeiture of restricted stock, which reduced expense by approximately $0.3 million.

Impairment Expense for the first half of 2017 was approximately $4.6 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 2017 included $3.8 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. 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 first half of 2017. 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, 2017, 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.

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Exploration Expense for the first half of 2017 was approximately $0.3 million, as compared to $1.7 million for the same period in 2016. Approximately $0.2 million of the expense incurred in 2017 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rental payments. 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. 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 2017 decreased approximately $0.3 million, or 0.9%, from $31.2 million for the same period in 2016. Contributing to the decrease in DD&A expense were lower depreciable asset values for 2016 impairments and the sale of Warrior South assets resulting in a decrease of $1.5 million, offset by a higher depreciable asset value for waterline facilities completed and abandonment of three work in progress unconventional wells resulting in an increase of $1.2 million during 2017 when compared to the same period in 2016.

Other Operating Expense for the first half of 2017 decreased to approximately $1.1 million from $1.0 million for the same period in 2016. The expense in 2016 was primarily related to a firm transportation contract associated with an area west of our core assets in Butler County, Pennsylvania.

Interest Expense for the six months ended June 30, 2017 was approximately $21.3 million as compared to $24.5 million for the same period in 2016. 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 interest charges incurred on the available but undrawn borrowing base of the Term Loan established in April 2017, and a decrease in interest expense capitalized to evaluated properties in 2017. We discuss our Senior Notes, term loan and revolving credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain (Loss) on Derivatives, net included a gain of approximately $18.8 million for the first half of 2017 as compared to a loss of $25.1 million for the same period in 2016. The gain recorded for the first half of 2017 included cash payments for commodity derivatives of $5.5 million while the loss incurred in the first half of 2016 included cash receipts of approximately $30.3 million for commodity 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 2017 and 2018, 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.

Gain (Loss) on Extinguishments of Debt for the six months ended June 30, 2017 totaled a loss of approximately $3.0 million.  The loss in 2017 reflects the write-off of approximately $3.4 million of unamortized debt issuance costs related to the Senior Credit Facility retired in April 2017, offset by approximately $0.4 million in gains from debt to equity exchanges completed in the six months ended June 30, 2017. Gain on extinguishments of debt for the second quarter of 2016 totaled approximately $23.7 million, resulting from debt to equity exchanges with certain holders of our Senior Notes. We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Expense for continuing operations for the first half of 2017 was $0.0 million, or 0.0% of pretax income, due to the full valuation allowances we maintain against our net deferred tax assets.

For the first half of 2016, income tax expense was $2.3 million. Our estimated annual effective tax rate for 2016 differed from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets coupled with recognizing tax benefits in continuing operations for the effect of taxable income generated by our discontinued operations. To a lesser extent, the annual effective rate is also influenced by alternative minimum tax with no corresponding deferred tax benefit due to the full valuation allowance, and state taxes in certain tax paying jurisdictions.  The Company’s alternative minimum tax due for 2016 was driven primarily by cancellation of debt income of $543.2 million related to the Senior Note exchanges.   

Net Loss Attributable to Rex Energy for the first half of 2017 was approximately $6.9 million, as compared to $114.7 million for the same period in 2016 as a result of factors discussed above.

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	Other Performance Measurements
	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2017		2016		2017		2016
EBITDAX from Continuing Operations ($ in Thousands) (a)	$	12,420	$	19,024	$	27,996	$	27,495
LOE per Mcfe	$	1.82	$	1.39	$	1.84	$	1.40
G&A per Mcfe	$	0.27	$	0.27	$	0.28	$	0.29

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

EBITDAX (Non-GAAP)

EBITDAX (Non-GAAP) from continuing operations increased approximately $0.5 million to $28.0 million for the six-month period ended June 30, 2017, as compared to the same period in 2016.  The increase in EBITDAX can be primarily attributed to the increased average sales prices for natural gas, NGLs and condensate, resulting in increased operating revenues, offset primarily by decreases in production and a decrease in cash receipts related to derivatives.

LOE per Mcfe

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 $0.43 to $1.82 for the three months ended June 30, 2017 as compared to $1.39 for the same period in 2016. LOE per Mcfe increased $0.44 to $1.84 for the six months ended June 30, 2017, as compared to $1.40 for the same period in 2016.  The increase in our LOE per Mcfe in each period can be attributed to our Gulf Coast transportation, which began in November 2016, which carries a heavier transportation burden while providing premium natural gas pricing. Our LOE is largely comprised of variable type costs such as transportation, marketing, processing and gathering. For the second quarter of 2017, transportation, capacity and processing fees accounted for approximately 89.9% of our total Production and Lease Operating Expense as compared to 86.5% during the same period of 2016. For the six months ended June 30, 2017, transportation, capacity and processing fees accounted for approximately 90.4% of our total Production and Lease Operating Expense as compared to 87.1% during the same period of 2016.  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.

G&A Expenses per Mcfe

Our G&A expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our G&A expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe were approximately $0.27 for the three month period ended June 30, 2017, as compared to $0.27 for the same period in 2016. During the first half of 2017, G&A per Mcfe was approximately $0.28 as compared to $0.29 for the same period of 2016.  The decreases are predominately due to reduced transactional costs during the first half of 2017 as compared to transactional costs associated with the BSP transaction during same period in 2016.

Capital Resources and Liquidity

On April 28, 2017, we entered into a Term Loan Credit Agreement (the “Term Loan”) and subsequently terminated and repaid amounts outstanding under our revolving credit facility (for additional information, see Note 7, Long Term Debt, to our Consolidated Financial Statements.

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the six months ended June 30, 2017, we spent $56.4 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 $13.4 million of costs incurred during the first half of 2017 that were not billed until the third quarter. We funded our capital program with proceeds from the sale of our Warrior South Assets, proceeds from the Term Loan, cash from operations and joint venture reimbursements received from BSP. The remainder of our 2017 capital budget is expected to be funded primarily by cash on hand, cash flows from operations, proceeds from the Term Loan 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,

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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, we have primarily used cash flows from operations, borrowings from lines of credit and net proceeds from debt and equity offerings to fund the exploration and development of our oil and gas interests. As of June 30, 2017, we had approximately $12.9 million of cash on hand and outstanding borrowings under our Term Loan of approximately $143.5 million with an additional $46.3 million of undrawn letters of credit outstanding. As of June 30, 2017, we had approximately $1110.2 million of undrawn availability on the Term Loan.

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 natural gas, NGL and condensate reserves. If commodity prices decrease, our operating cash flows may decrease, which could reduce 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 natural gas, NGL and condensate 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 Term Loan.  We expect to be in compliance with all required debt covenants for at least the twelve month period following the filing date of our Form 10-Q report for the quarterly reporting period ended June 30, 2017.

Due to the depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock (“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. In April 2017, we resumed the quarterly dividend cycle by declaring a quarterly dividend of $150.00 per share on our Preferred Stock ($1.50 per depositary share, each representing 1/100 interest in a share of Preferred Stock) payable on May 15, 2017; this dividend payment was applied to the earliest dividend in arrears at the time of payment. In July 2017, we declared a quarterly dividend in the same amount; this dividend payment will be made on August 15, 2017, and will be applied to the earliest dividend still in arrears at the time of payment.  Any subsequent quarterly dividends declared and paid will be applied to the earliest dividend then in arrears until the arrearage is satisfied and dividends are current. As a result of having dividends in arrears on our Preferred Stock, we are not currently 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 public offerings of 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, 2017, our Fixed Charge Coverage Ratio was 1.05 to 1.00.  We expect our Fixed Charge Coverage Ratio to improve in 2017 based on our projections of decreased interest expense related to our Senior Notes, increased production and improved price realizations.  As of June 30, 2017, we were limited to incurring approximately $75.2 million in additional 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 were not restricted as to our borrowings under our Term Loan; 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.

Future Liquidity Considerations

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay minimum fees in connection with these agreements of $202.3 million over the next five years, depending on our levels of production. In connection with certain of these agreements, weconcurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $391.5 millionover the life of the agreements. These guarantees will decrease over time as the commitments are satisfied.

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Our Term Loan contains a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. Our financial covenants require us to maintain a maximum “Ratio of Net Senior Secured Debt to EBITDAX” of 3.25 to 1.0, a minimum “Ratio of EBITDAX to Interest Expense” of 1.0 to 1.0, increasing to 1.3 to 1.0 for quarterly periods ending on or after March 31, 2018 and a minimum “PDP Coverage Ratio” of 1.65 to 1.00. Failure to comply with these covenants could have a material adverse effect on our business. As of June 30, 2017, our Net Senior Secured Debt to EBITDAX Ratio was 2.33 to 1.00.  If an event of default under our Term Loan occurs and remains uncured, among other things, the lenders thereunder:

• Would not be required to lend any additional amounts to us;

• Could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

• May have the ability to require us to apply all of our available cash to repay these borrowings; or

• May prevent us from making debt service payments under our other agreements.

In order to improve our liquidity positions to meet the financial requirements under our Term Loan 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) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from any 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, 2017 and 2016

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

	Six Months Ended June 30,
($ in Thousands)	2017			2016
Cash flows provided by (used in) operations	$	23,310		$	(4,637	)
Cash flows used in investing activities		(31,274	)		(23,987	)
Cash flows provided by financing activities		17,122			30,971
Net increase in cash and cash equivalents	$	9,158		$	2,347

Net cash provided by operating activities during the first six months of 2017 increased $27.9 million from net cash used by operating activities during the same period in 2016. This was primarily due to increases in realized prices of our natural gas, condensate and C3+ NGL sales, and decreased cash interest outflow of approximately $16.1 million as a result of our debt restructuring events in 2016, partially offset by decreased production.

Net cash used in investing activities during the first six months of 2017 increased $7.3 million from net cash used by investing activities during the same period in 2016. This was due to capital development expenditures in the first six months of 2017 that were approximately $16.3 million higher than in the first six months of 2016, coupled with the effect of joint venture capital reimbursements of approximately $19.5 million we received in 2016, reducing our net capital expenditure outflow in the first six months of 2016. These factors account for a net increase in cash used in investing activities of $31.8 million for the first six months of 2017 compared to the first six months of 2016. This increase was partially offset by cash proceeds of approximately $24.5 million received in January 2017, from the sale of our Warrior South assets.

Net cash provided by financing activities during the first six months of 2017 decreased by approximately $13.8 million from net cash provided by financing activities during the same period in 2016, primarily due to repayments of our revolving credit facility borrowings and debt issuance costs.

As market conditions warrant and subject to our contractual restrictions in the Term Loan, our Indentures 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 outstanding equity securities or outstanding debt, including our Senior Notes, by tender offer, exchange or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Effects of Inflation and Changes in Price

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

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Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended June 30, 2017, 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, 2016. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 5, “Recently Issued Accounting Pronouncements.”

Non-GAAP Financial Measures

EBITDAX

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

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

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

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

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

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

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

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.

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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)	2017			2016			2017			2016
Net Loss From Continuing Operations	$	(9,603	)	$	(52,911	)	$	(6,920	)	$	(105,562	)
Add Back Non-Recurring Costs1		3,349			(23,174	)		3,459			(14,694	)
Add Back Depletion, Depreciation, Amortization and Accretion		15,501			14,750			30,969			31,262
Add Back Non-Cash Compensation Expense		511			1,164			571			1,016
Add Back Interest Expense		12,123			11,439			21,271			24,469
Add Back Impairment Expense		3,032			25,139			4,577			35,780
Add Back Exploration Expenses		99			803			319			1,738
Less Gain on Disposal of Assets		(124	)		(4,307	)		(1,959	)		(4,295	)
Less (Gain) Loss on Financial Derivatives		(10,386	)		29,169			(18,766	)		25,120
Add Back (Less) Cash Settlement of Derivatives		(2,082	)		17,345			(5,525	)		30,340
(Less) Add Back Income Tax (Benefit) Expense		—			(393	)		—			2,321
EBITDAX From Continuing Operations	$	12,420		$	19,024		$	27,996		$	27,495
Net Loss From Discontinued Operations	$	—		$	(1,683	)	$	—		$	(9,173	)
Add Back Depletion, Depreciation, Amortization and Accretion		—			2,186			—			5,083
Add Back Non-Cash Compensation Expense		—			139			—			259
Add Back Interest Expense		—			1			—			3
Add Back Impairment Expense		—			—			—			3,543
Add Back Exploration Expenses		—			85			—			143
Less Gain on Disposal of Assets		—			(2	)		—			(43	)
Add Back (Less) Income Tax Expense (Benefit)		—			120			—			(502	)
Add EBITDAX From Discontinued Operations	$	—		$	846		$	—		$	(687	)
EBITDAX (Non-GAAP)	$	12,420		$	19,870		$	27,996		$	26,808

1 For the three months ended June 30, 2017, includes a net $0.1 million of advisory services related to our joint venture drilling programs, and $3.3 million in loss on the extinguishment of debt. For the six months ended June 30, 2017, includes a net $0.4 million of advisory services related to our joint venture drilling programs, and $3.0 million in loss on the extinguishment of debt.  For the three months ended June 30, 2016, includes approximately $23.7 million in gains on extinguishment of debt and $0.5 million in debt exchange expenses.  For the six months ended June 30, 2016, includes approximately $23.7 million in gains on extinguishment of debt and $9.0 million in debt exchange expenses.

Volatility of Oil, NGL and Natural Gas Prices

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

For the three and six months ended June 30, 2017, we paid net settlements on oil, NGL and natural gas derivatives of approximately $2.1 million and $5.5 million, respectively, as compared to receiving net settlements of approximately $17.4 million and $30.5 million for the same period in 2016. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of June 30, 2017, we had over 75.0% of our annualized condensate production hedged through the remainder of 2017, over 90.0% and 60% of our annualized natural gas production hedged through the remainder of 2017 and 2018, respectively, and over 70.0% and 50% of our annualized NGL production hedged through the remainder of 2017 and 2018, respectively. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion activity or the natural decline of our 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 basis differentials when compared to NYMEX pricing. During the six months ended June 30, 2017, our average realized prices for natural gas were higher than the average NYMEX prices over the same period by approximately $0.03 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 Dominion South basis swaps in place for 5,635 MMcf at an average differential to Henry Hub NYMEX of $0.80 per Mcf for the remainder of 2017 in addition to Dominion South basis swaps for 12,775 MMcf at an average differential to Henry Hub NYMEX of $0.83 per Mcf for 2018. For the six months ended June 30, 2017, we paid cash settlements on our basis differential derivatives of approximately $1.7 million.

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 have entered into all of our derivatives transactions with two 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.

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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 oil, NGL and natural gas derivative positions at June 30, 2017, refer to Part I, Item 1. Financial Statements - Note 8, “Derivative Instruments and Fair Value Measurements”.

Contractual Obligations

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. Our contractual obligations include long-term debt, operating leases, operational commitments, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2016, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our borrowings under the former Senior Credit Facility and current Term Loan. See Part I, Item 1. Financial Statements—Note 7, “Long-Term Debt” for additional information on the Senior Credit Facility and Term Loan.

Off-Balance Sheet Arrangements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, NGLs and natural gas. Conversely, increases in the market prices for oil, NGLs and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on production through June 30, 2017, 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 2017 average would reduce our gross revenues, before the effects of derivatives, for the remaining six months of 2017 by approximately $9.9 million.

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

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At June 30, 2017, we had the following commodity derivative contracts outstanding:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2017 - Swaps		30,000	Bbls	$	—	$	—	$	—	$	54.00		$	175
2017 - Three-Way Collars		78,000	Bbls		39.62		49.23		61.35		—			228
2018 - Swaps		60,000	Bbls		—		—		—		54.00			350
2018 - Collars		18,000	Bbls		—		53.00		60.00		—			113
2018 - Three-Way Collars		60,000	Bbls		43.00		52.00		62.30		—			211
2019 - Swaps		31,500	Bbls		—		—		—		51.00			21
2019 - Three-Way Collars		21,000	Bbls		37.50		47.50		59.00		—			6
2020 - Swaps		24,000	Bbls		—		—		—		51.00			21
2020 - Three-Way Collars		3,000	Bbls		37.50		47.50		59.00		—			1
2021 - Swaps		6,000	Bbls		—		—		—		51.00			5
		331,500	Bbls										$	1,131
Natural Gas
2017 - Swaps		5,990,000	Mcf		—		—		—		3.12		$	234
2017 - Swaptions		1,200,000	Mcf		—		—		—		3.33			269
2017 - Cap Swaps		1,800,000	Mcf		2.25		—		—		2.70			(703	)
2017 - Collars		1,100,000	Mcf		—		2.62		3.25		—			(48	)
2017 - Three-Way Collars		8,490,000	Mcf		2.29		2.98		3.86		—			669
2017 - Calls		1,500,000	Mcf		—		—		3.64		—			(154	)
2017 - Basis Swaps - Dominion South		5,635,000	Mcf		—		—		—		(0.80	)		(688	)
2017 - Basis Swaps - Texas Gas		7,360,000	Mcf		—		—		—		(0.13	)		4
2018 - Swaps		15,335,000	Mcf		—		—		—		3.10			1,321
2018 - Swaptions		—	Mcf		—		—		—		—			(143	)
2018 - Three-Way Collars		8,775,000	Mcf		2.30		2.89		3.58		—			228
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(527	)
2018 - Collars		450,000	Mcf		—		3.20		3.65		—			38
2018 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.83	)		(3,029	)
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf								(0.13	)		8
2019 - Swaps		6,350,000	Mcf		—		—		—		2.91			26
2019 - Three-Way Collars		5,000,000	Mcf		2.35		2.85		3.60		—			46
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(3,256	)
2020 - Swaps		3,660,000	Mcf		—		—		—		2.90			(29	)
2020 - Three-Way Collars		1,810,000	Mcf		2.35		2.85		3.60		—			46
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(1,722	)
2021 - Swaps		900,000	Mcf		—		—		—		2.90			(7	)
2021 - Three-Way Collars		300,000	Mcf		2.35		2.85		3.60		—			12
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(526	)
		143,535,000	Mcf										$	(9,509	)
NGLs
2017 - C3+ NGL Swaps		841,000	Bbls		—		—		—		29.70		$	(779	)
2017 - Ethane Swaps		450,000	Bbls		—		—		—		10.50			(54	)
2018 - C3+ NGL Swaps		1,110,000	Bbls		—		—		—		31.50			3,102
2018 - Ethane Swaps		750,000	Bbls		—		—		—		13.02			539
2019 - C3+ NGL Swaps		353,250	Bbls		—		—		—		26.04			200
2019 - C5 Collars		113,040	Bbls		—		44.94		55.02		—			5
2019 - Ethane Swaps		480,000	Bbls		—		—		—		13.02			130
2020 - C3+ NGL Swaps		135,000	Bbls		—		—		—		24.78			256
2020 - C5 Collars		28,260	Bbls		—		44.94		55.02		—			1
2020 - Ethane Swaps		48,000	Bbls		—		—		—		13.44			(3	)
2021 - C3+ NGL Swap		30,000	Bbls		—		—		—		24.78			62
2021 - Ethane Swaps		9,000	Bbls		—		—		—		13.44			(1	)
		4,347,550	Bbls										$	3,458

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 June 30, 2017, 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, 2016. Based on our total debt as of June 30, 2017, of approximately $789.4 million, a 0.1% change in interest rates would impact our interest expense by approximately $8.0 million.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, 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, 2017, our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

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

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PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

During the quarter ended June 30, 2017, 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, 2016.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

None.

Item 5. Other Information.

None.

Item 6.Exhibits.

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

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SIGNATURES

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

	REX ENERGY CORPORATION (Registrant)
Date: August 9, 2017	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)

Date: August 9, 2017	By:	/s/ Thomas Rajan
		Thomas Rajan
		Chief Financial Officer (Principal Financial Officer)

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EXHIBIT INDEX

Exhibit Number	Exhibit Title
3.1*	Certificate of Incorporation of Rex Energy Corporation, as amended to date.
3.2*	Amended and Restated Bylaws of Rex Energy Corporation, as amended to date.
10.1	Term Loan Credit Agreement, effective as of April 28, 2017, by and among Rex Energy Corporation, Angelo, Gordon Energy Servicer, LLC, as Administrative Agent and Collateral Agent, Macquarie Bank Limited, as Issuing Bank and the lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on May 12, 2017).
10.2	Amended and Restated Guaranty and Collateral Agreement, dated as of April 28, 2017, made by Rex Energy Corporation and each of the other grantors (as defined therein) in favor of the Collateral Agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on May 12, 2017).
31.1*	Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2*	Certification of Chief Financial Officer (Principal Financial Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* These exhibits are filed herewith.

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