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 ~~March~~June 3130, 2018

☐	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.

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 ☒

10,~~708~~707,~~287~~788 shares of common stock were outstanding on ~~May~~August 106, 2018.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~MARCH~~JUNE 3130, 2018

INDEX

			PAGE
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	5
		Consolidated Balance Sheets as of March 31. 2018 (Unaudited) and December 31, 2017	5
		Consolidated Balance Sheets as of June 30. 2018 (Unaudited) and December 31, 2017	5
		Consolidated Statements of Operations (Unaudited) for the three-month periods ended March 31, 2018 and March 31, 2017	6
		Consolidated Statements of Operations (Unaudited) for the three and six-month periods ended June 30, 2018 and June 30, 2017	6
		Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the three-month period ended March 31, 2018	7
		Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the six-month period ended June 30, 2018	7
		Consolidated Statements of Cash Flows (Unaudited) for the three-month periods ended March 31, 2018 and March 31, 2017	8
		Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2018 and June 30, 2017	8
		Notes to Consolidated Financial Statements (Unaudited)	9
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	4044
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	5261
	Item 4.	Controls and Procedures	5463
PART II. OTHER INFORMATION			5564
	Item 1.	Legal Proceedings	5564
	Item 1A.	Risk Factors	5564
	Item 6.	Exhibits	5667
SIGNATURES			5768

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:

•

our ability to restructure our balance sheet in a manner that allows us to continue as a going concern over the long term;

•

our ability to successfully complete a reorganization under Chapter 11 and emerge from bankruptcy;

•

potential adverse effects of our pending Chapter 11 proceedings on our liquidity and results of operations;

•

our ability to obtain timely Bankruptcy Court approval with respect to motions filed in the Bankruptcy Petitions;

•

objections to our plan of reorganization that could protract our pending Chapter 11 proceedings;

•

our ability to service our outstanding indebtedness;

•

our ability to comply with the restrictions imposed by our Debtor-In-Possession financing agreement and other financing arrangements;

•

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 senior credit facility and other existing and future financing arrangements;

•

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

•

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

•

impairments of our natural gas and oil asset values due to declines in commodity prices;

•

economic conditions in the United States and globally;

•

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 oil reserves;

•

our ability to increase natural gas, NGL and oil 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 gas and oil 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;

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

• uncertainties related to the ~~success~~legal ofand regulatory environment for our ~~business~~industry and ~~financial~~our ~~strategies,~~own legal proceedings and ~~hedging~~their ~~strategies;~~outcome.

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

• the eligibility of our common stock for quotation of the OTC Bulletin Board or OTC Markets Group’s Pink marketplace following the delisting of the Company’s common stock from the Nasdaq Stock Market LLC (“Nasdaq”).

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.

Item 1.

Financial Statements.

REX ENERGY CORPORATION (DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS

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

	March 31, 2018 (unaudited)			December 31, 2017
	June 30, 2018 (unaudited)			December 31, 2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	2528,~~090~~780		$	15,247
Accounts Receivable		27,147			25,974
Restricted Cash		33,106			—
Accounts Receivable		28,588			25,974
Taxes Receivable		48			2,049
Short-Term Derivative Instruments		74,~~732~~796			8,008
Inventory, Prepaid Expenses and Other		93,~~997~~389			4,614
Total Current Assets		7098,~~014~~707			55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		~~991~~1,~~617~~062,986			1,086,625
Unevaluated Oil and Gas Properties		~~179~~174,~~297~~608			186,523
Other Property and Equipment		1920,~~792~~066			19,640
Wells and Facilities in Progress		522,~~271~~552			38,660
Pipelines		16,~~803~~528			16,803
Total Property and Equipment		1,~~259~~276,~~780~~740			1,348,251
Less: Accumulated Depreciation, Depletion and Amortization		(~~367~~384,~~900~~556	)		(463,899	)
Net Property and Equipment		~~891~~892,~~880~~184			884,352
Other Assets		35			44
Long-Term Derivative Instruments		21,~~880~~463			1,719
Deferred Tax Assets - Long Term		130			130
Total Assets	$	~~964~~992,~~939~~519		$	942,137
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	7082,~~394~~679		$	62,354
Current Maturities of Long-Term Debt		~~869~~261,~~197~~315			834,325
Accrued Liabilities		49,243			45,218
Debtor-in Possession Term Loan Payable		35,000			—
Short-Term Derivative Instruments		64,671			14,892
Accrued Liabilities		30,936			45,218
Total Current Liabilities		1,053,505			956,789
Short-Term Derivative Instruments		19,095			14,892
Long-Term Derivative Instruments		10,576			14,249
Total Current Liabilities		429,025			956,789
Other Long-Term Debt		7,972			8,156
Long-Term Derivative Instruments		12,075			14,249
Other Deposits and Liabilities		6,866			7,153
Other Long-Term Debt		—			8,156
Future Abandonment Cost		8,355			9,352
Other Deposits and Liabilities		—			7,153
Total Liabilities	$	1,087,274		$	995,699
Future Abandonment Cost		8,626			9,352
Commitments and Contingencies (See Note 12)
Liabilities Subject to Compromise		667,624			—
Total Liabilities	$	1,117,350		$	995,699
Commitments and Contingencies (See Note 13)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on March 31, 2018 and December 31, 2017	$	1		$	1
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on June 30, 2018 and December 31, 2017	$	1		$	1
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 10,708,287 shares issued and outstanding on March 31, 2018 and 10,244,394 shares issued and outstanding on December 31, 2017.		11			10
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 10,707,788 shares issued and outstanding on June 30, 2018 and 10,244,394 shares issued and outstanding on December 31, 2017.		11			10
Additional Paid-In Capital		654,~~534~~721			652,917
Accumulated Deficit		(~~776~~779,~~881~~564	)		(706,490	)
Total Stockholders’ Equity		(~~122~~124,~~335~~831	)		(53,562	)
Total Liabilities and Stockholders’ Equity	$	~~964~~992,~~939~~519		$	942,137

See accompanying notes to the unaudited consolidated financial statements

REX ENERGY CORPORATION (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF OPERATIONS

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

	For the Three Months Ended March 31,
	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	6575,~~025~~155		$	5247,~~065~~457		$	140,180		$	99,522
Other Operating Revenue		43			65			7			11
TOTAL OPERATING REVENUE		6575,~~029~~158			5247,~~071~~462			140,187			99,533
OPERATING EXPENSES
Production and Lease Operating Expense		3336,~~846~~756			2829,~~934~~374			70,602			58,308
General and Administrative Expense		64,~~525~~422			4,~~534~~294			10,946			8,828
Loss (Gain) on Disposal of Assets		647			(1,834	)
(Gain) Loss on Disposal of Assets		—			(124	)		647			(1,959	)
Impairment Expense		84,~~168~~334			13,~~546~~032			12,503			4,577
Exploration Expense		~~228~~122			~~220~~99			350			319
Depreciation, Depletion, Amortization and Accretion		1516,~~128~~953			15,~~468~~501			32,081			30,969
Other Operating (Income) Expense		~~203~~1,492			(2198	)		1,695			(118	)
TOTAL OPERATING EXPENSES		64,~~745~~079			4852,~~847~~078			128,824			100,924
INCOME FROM OPERATIONS		284			3,224
INCOME (LOSS) FROM OPERATIONS		11,079			(4,616	)		11,363			(1,391	)
OTHER INCOME (EXPENSE)
Interest Expense		(2214,~~647~~118	)		(912,~~143~~122	)		(36,765	)		(21,266	)
(Loss) Gain on Derivatives, Net		(4614,~~426~~328	)		810,~~381~~386			(60,754	)		18,766
Other Expense		(1,004	)		(28	)
Other (Expense) Income		(13,952	)		20			(14,955	)		(7	)
Gain on Extinguishments of Debt		—			249
Loss on Extinguishments of Debt		—			(3,271	)		—			(3,022	)
TOTAL OTHER EXPENSE		(70,077	)		(541	)
Reorganization Items, Net		28,635			—			28,635			—
INCOME (LOSS) BEFORE INCOME TAX		(69,793	)		2,683
TOTAL OTHER EXPENSE		(13,763	)		(4,987	)		(83,839	)		(5,529	)
Income Tax Benefit		—			—
LOSS BEFORE INCOME TAX		(2,684	)		(9,603	)		(72,476	)		(6,920	)
NET (LOSS) INCOME		(69,793	)		2,683
Income Tax Benefit		—			—			—			—
Preferred Stock Dividends		(598	)		(598	)
NET LOSS		(2,684	)		(9,603	)		(72,476	)		(6,920	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(70,391	)	$	2,085
Preferred Stock Dividends		(598	)		(598	)		(1,196	)		(1,196	)
Earnings per common share:
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(3,282	)	$	(10,201	)	$	(73,672	)	$	(8,116	)
Basic - Net (Loss) Income Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	0.21
Earnings per common share:
Basic - Weighted Average Shares of Common Stock Outstanding		10,464			9,769
Basic - Net Loss Attributable to Rex Energy Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)
Diluted - Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	0.21
Basic - Weighted Average Shares of Common Stock Outstanding		10,708			9,881			10,587			9,825
Diluted - Weighted Average Shares of Common Stock Outstanding		10,464			9,769
Diluted - Net Loss Attributable to Rex Energy Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)
Diluted - Weighted Average Shares of Common Stock Outstanding		10,708			9,881			10,587			9,825

See accompanying notes to the unaudited consolidated financial statements

REX ENERGY CORPORATION (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

FOR THE ~~THREE~~SIX-MONTHS ENDED ~~MARCH~~JUNE 3130, 2018

(Unaudited, in Thousands)

	Common Stock					Preferred Stock
	Shares			Par Value		Shares		Par Value		Additional Paid- In Capital		Accumulated Deficit			Total Stockholders’ Equity (Deficit)
BALANCE December 31, 2017		10,244		$	10		4	$	1	$	652,917	$	(706,490	)	$	(53,562	)
Equity Based Compensation		—			—		—		—		1,~~019~~206		—			1,~~019~~206
Issuance of Restricted Stock, Net of Forfeitures		(27	)		—		—		—		—		—			—
Preferred Dividends in Arrears Paid in Common Shares		491			1		—		—		598		(598	)		1
Net Loss		—			—		—		—		—		(6972,~~793~~476	)		(6972,~~793~~476	)
BALANCE March 31, 2018		10,708		$	11		4	$	1	$	654,534	$	(776,881	)	$	(122,335	)
BALANCE June 30, 2018		10,708		$	11		4	$	1	$	654,721	$	(779,564	)	$	(124,831	)

See accompanying notes to the unaudited consolidated financial statements

REX ENERGY CORPORATION (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Three Months Ended March 31,
	For the Six Months Ended June 30,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(69,793	)	$	2,683
Net Loss	$	(72,476	)	$	(6,920	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion		1532,~~128~~081			1530,~~468~~969
Loss (Gain) on Derivatives		4660,~~426~~754			(818,~~381~~766	)
Cash Settlements of Derivatives		(2,009	)		(3,443	)
Cash Settlement of Derivatives		(6,862	)		(5,525	)
Equity-based Compensation Expense		1,~~018~~200			71571
Non-cash Exploration Expenses		—			1113
Impairment Expense		812,~~168~~503			14,~~546~~577
Non-cash Interest Expense		42,~~161~~881			612,~~081~~431
Gain on Extinguishments of Debt		—			(249	)
Loss on Extinguishments of Debt		—			3,022
(Gain) Loss on Sale of Assets		647			(1,834	)
Loss (Gain) on Sale of Assets		647			(1,959	)
Other Non-cash (Income) Expense		380			(66	)
Non-cash Reorganization items, net		(43,509	)		—
Other Non-cash Expenses		566			41
Changes in operating assets and liabilities
Accounts Receivable		96(342	)		57,~~341~~229
Taxes Receivable		2,001			—163
Inventory, Prepaid Expenses and Other Assets		~~(5,853~~336	)		~~422~~52
Accounts Payable and Accrued Liabilities		2541,~~637~~478			(61,~~989~~484	)
Other Assets and Liabilities		(89147	)		(~~139~~1,104	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		2531,~~918~~111			1023,~~522~~310
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		16,~~188~~384			24,~~329~~513
Acquisitions of Undeveloped Acreage		(~~620~~871	)		(~~299~~1,783	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(61100,~~738~~136	)		(2554,~~476~~004	)
NET CASH USED IN INVESTING ACTIVITIES		(4684,~~170~~623	)		(131,~~446~~274	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts		3069,~~555~~846			21171,~~500~~000
Repayments of Long-Term Debt and Line of Credit		—			(28,500	)
Proceeds from Debtor-In-Possession Financing		35,000			—
Repayments of Loans and Other Notes Payable		(460	)		(131	)
Repayments of Long-Term Debt and Line of Credit		—			(145,170	)
Debt Issuance Costs		—			(567	)
Repayments of Loans and Other Notes Payable		(945	)		(319	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		30,095			(7,698	)
Reorganization Item - Debtor-In-Possession Financing Fee		(3,750	)
NET INCREASE IN CASH		9,843			1,378
Debt Issuance Costs		—			(7,791	)
CASH – BEGINNING		15,247			3,697
Payment of Preferred Dividends in Arrears		—			(598	)
CASH – ENDING	$	25,090		$	5,075
NET CASH PROVIDED BY FINANCING ACTIVITIES		100,151			17,122
Net Increase in Cash, Cash Equivalents and Restricted Cash		46,639			9,158
Beginning Cash, Cash Equivalents and Restricted Cash		15,247			3,697
Ending Cash, Cash Equivalents and Restricted Cash	$	61,886		$	12,855
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	$	5,594		$	1,541
Cash and Cash Equivalents	$	28,780		$	12,855
Cash (Received) Paid for Income Taxes		(2,001	)		(163	)
Restricted Cash required to collateralize Letters of Credit (See Note 13)		33,106			—
Total Ending Cash, Cash Equivalents and Restricted Cash	$	61,886		$	12,855
Interest Paid, net of capitalized interest	$	11,965		$	8,494
Cash Received for Income Taxes		(2,001	)		(163	)
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin	$	—729		$	(1,~~417~~893	)
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets		150			5,000
Increase (Decrease) in Accounts Payable and Accrued Liabilities for Capital Expenditures		(1330,~~730~~943	)		(31,~~040~~652	)
Increase Long Term Debt - Equipment Financing		345			607
Increase in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions		—			5,208
Decrease in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions		—			(879	)
Decrease in Bond Interest Payable due to Debt to Equity Conversions		—			(1112	)
Increase in Common Stock outstanding due to Debt to Equity Conversions		—			~~281~~467

See accompanying notes to the unaudited consolidated financial statements

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, 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, NGL 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 natural gas, NGLs and crude oil, 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 natural gas, NGL and oil 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. 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, 2017.

~~Ability~~Consolidation toof ~~Continue~~Guarantor ~~as a Going Concern, Covenant Violations and Planned Chapter 11 Reorganization~~Subsidiaries

AsSubsequent of May 15, 2018, the date we filed our Consolidated Financial Statements with the Securities and Exchange Commission on Form 10-Q for the quarterly period ended March 31, 2018, we have not yet made the semi-annual interest payment to the ~~holders~~sale of our ~~second~~Illinois ~~lien~~Basin ~~notes~~operations ~~that was due April 2, 2018. The second lien notes provide for a 30-day grace period~~ in ~~which to pay the interest coupon due to the noteholders~~2016, ~~which expired on May 2, 2018. Nonpayment of the interest due has resulted in an event of default under~~ our ~~term~~subsidiaries ~~loan~~Rex ~~agreement~~Energy ~~and the second lien indentures. We received a notice of acceleration on April 27~~IV, ~~2018,~~LLC ~~from the lenders under our term loan agreement demanding immediate payment of all outstanding notes~~ and ~~loans,~~Penntex ~~together~~Resources ~~with all accrued interest~~Illinois, ~~fees, yield maintenance and call protection amounts~~Inc. Aswere ofdormant ~~March~~entities ~~31,~~with ~~2018,~~no weassets ~~recorded~~or ~~at fair value a liability for the yield maintenance and call protection amounts of approximately $53~~operations.0 ~~million,~~Effective ~~recorded~~April ~~as Short-Term Derivative Instruments on our Consolidated Balance Sheet (see Note8~~10, ~~Derivative Instruments and Fair Value Measurements and Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information). For the three months ended March 31,~~ 2018, we ~~recorded~~consolidated aRex ~~loss~~Energy ~~of approximately $53.0 million as Gain (Loss) on Derivatives~~IV, ~~Net~~LLC in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which have led to the Company deciding to file Chapter 11 Bankruptcy which have caused these amounts to become due and ~~payable. The~~Penntex ~~outstanding~~Resources ~~balance of the term loan inclusive of the yield maintenance~~Illinois, ~~call protection, accrued interest and fees was approximately $274~~Inc.0 ~~million~~by asway of ~~March~~a ~~31,~~merger ~~2018. In addition to the non-payment of second lien interest, we also encountered additional events of default related to certain non-financial covenants associated~~ with our term loan agreement. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited quarterly financial statements for the quarter ended December 31, 2017 and ~~our~~into ~~annual~~Rex ~~audited~~Energy ~~financial statements for the year ended December 31~~I, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and written notices of the events of default in a subsequent draw request under the term loan agreementLLC.

WeBankruptcy have entered into forbearance agreements with each of the requisite lenders under our senior term loan facility and the second lien notes. The forbearance agreements do not constitute a waiver of the events of default related to the nonpayment of interest and other non-financial covenants defaults described above. The forbearance agreements specify that the lenders will forbear from taking any enforcement actions during the forbearance period, which extends through May 17, 2018, unless earlier terminated, but does not prevent acceleration of amounts owed. We do not have sufficient liquidity to repay these amounts. The Company has been unsuccessful in negotiating an alternative restructuring with its various stakeholders outside of a voluntary pre-arranged Chapter 11 bankruptcy filing. As such, the ability to conclude a successful negotiation with our lenders and note holders out of court is not expected to occur. An acceleration notice from the lenders of our senior term loan has been received and we lack the liquidity to pay these obligations. Given these circumstances, the Company is currently in the process of preparing to file for protection under Chapter Accounting

On May 18, 2018 (the “Petition Date”), the Company and certain of its direct subsidiaries (collectively with the Company, the “Rex Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Western District of Pennsylvania (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Debtors will operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

The consolidated financial statements have been prepared as if we are a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization Items, Net” on our consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “Liabilities Subject to Compromise” on our consolidated balance sheet at June 30, 2018. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less.

11The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the UChapter 11 proceedings.S. ~~Bankruptcy~~In ~~Code~~particular, ~~which~~the isconsolidated ~~expected~~financial tostatements ~~occur~~do ~~imminently~~not ~~following~~purport to show: (i) the ~~filing~~realizable value of ~~this~~assets ~~Form~~on ~~10-Q.~~a ~~There~~liquidation ~~can~~basis beor notheir ~~assurances~~availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the ~~Company~~status ~~will~~and priority thereof; (iii) the effect on shareholders’ deficit accounts of any changes that may be ~~able~~made to ~~reorganize~~our ~~its~~capitalization; ~~capital~~or ~~structure~~(iv) the effect on ~~terms~~operations ~~acceptable~~of any changes that may be made to our business. While operating as debtors-in-possession under Chapter 11 of the ~~Company~~Bankruptcy Code, ~~its~~we ~~creditors~~may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on our consolidated financial statements, subject to the approval of the Bankruptcy Court or atotherwise ~~all~~as permitted in the ordinary course of business. Further, a plan of reorganization (a “Plan”) could materially change the amounts and classifications on our historical consolidated financial statements.

~~The~~Use ~~events~~ of default and significant risks and uncertainties described above raise a substantial doubt about our ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of our discussions with the lenders under the term loan agreement and the holders of our second lien notes, or the outcome of the going concern uncertainty.Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of natural gas, NGLs, and oil future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

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.

2. ~~FUTURE~~PETITION ~~ABANDONMENT~~RELIEF ~~COST~~UNDER CHAPTER 11 AND GOING CONCERN ASSESSMENT

~~Future~~Chapter 11 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. Proceedings

~~Accretion~~On ~~expense totaled $0.3 million and $0.6 million for~~ the ~~three~~Petition ~~months ended March 31~~Date, ~~2018~~the ~~and~~Rex ~~2017,~~Debtors ~~respectively. These~~filed ~~amounts~~Bankruptcy ~~are~~Petitions ~~recorded~~for asrelief ~~depreciation,~~under ~~depletion,~~Chapter 11 ~~amortization~~of ~~and~~the ~~accretion~~Bankruptcy ~~(“DD&A”)~~Code ~~expense~~in onthe ~~our~~Bankruptcy ~~Consolidated Statements of Operations~~Court. WeThe ~~account~~Rex ~~for~~Debtors’ ~~future~~Chapter 11 ~~abandonment~~cases ~~costs~~are ~~that~~being ~~relate~~administered tojointly ~~wells~~under ~~that~~the ~~are~~caption ~~drilled~~In ~~jointly~~re ~~based~~R.E. onGas ~~our~~Development, ~~working~~LLC, ~~interest~~et inal., ~~those~~Case ~~wells~~No. 18-22032.

($ in Thousands)	March 31, 2018
Beginning Balance at January 1, 2018	$	9,939
Future Abandonment Obligation Incurred	$	1
Future Abandonment Obligation Settled	$	(100	)
Future Abandonment Obligation Cancelled or Sold	$	(878	)
Future Abandonment Obligation Revision of Estimated Obligation	$	99
Future Abandonment Obligation Accretion Expense	$	257
Total Future Abandonment Cost1	$	9,318

The Rex Debtors are operating their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted certain relief requested by the Rex Debtors, allowing us to use our cash to fund the Chapter 11 proceedings, pursuant to an agreement with the first lien lenders, and giving us the authority to, among other things, continue to pay employee wages and benefits without interruption, to utilize our current cash management system and to make royalty payments. During the pendency of the Chapter 11 proceedings, all transactions outside the ordinary course of our business require prior approval of the Bankruptcy Court. For goods and services provided following the Petition Date, we intend to pay vendors in full under normal terms.

1 Includes approximately $1.0 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

3. REVENUE RECOGNITION

Effective January 1, 2018, we adopted Accounting Standards Codification (“ASC”) 606, “Revenue from Contracts with Customers,” using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Under the modified retrospective method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no material adjustment was required as a result of adopting ASC 606. Results for reporting periods beginning on January 1, 2018 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company performed an analysis of the impact of adopting ASC 606 across all revenue streams and did not identify any changes to its revenue recognition policies that would result in a material impact to its consolidated financial statements. The Company also

~~implemented~~In ~~processes~~order ~~and~~to ~~controls~~exit Chapter 11 successfully, the Rex Debtors will need to ~~ensure~~obtain ~~new~~confirmation ~~contracts~~by ~~are~~the ~~reviewed~~Bankruptcy Court of a Plan that satisfies the requirements of the Bankruptcy Code. On July 25, 2018, the Debtors filed with the Bankruptcy Court a proposed Plan (as may be amended, modified or supplemented from time to time, the “Proposed Plan”) for the ~~appropriate~~resolution ~~accounting~~of ~~treatment~~the outstanding claims against and interests in the Debtors pursuant to ~~generate~~the Bankruptcy Code. On July 25, 2018, the ~~required~~Debtors ~~disclosures~~filed ~~under~~with the ~~standards~~Bankruptcy Court a related proposed disclosure statement (as may be amended, modified or supplemented from time to time, the “Proposed Disclosure Statement”). In addition to being voted on by holders of impaired claims and equity interests, the Proposed Plan must satisfy certain requirements of the Bankruptcy Code and must be approved, or confirmed, by the Bankruptcy Court in order to become effective. If accepted by holders of impaired claims and equity interests, the Proposed Plan would, among other things, resolve the Debtors’ prepetition obligations, and set forth the revised capital structure of the newly reorganized entity, unless all or substantially all of the Debtors' assets are sold during the Chapter 11 proceedings. The Debtors will seek approval of the Proposed Disclosure Statement on August 23, 2018, and, if obtained, will solicit votes on the Proposed Plan.

~~Revenues~~Under ~~Sources~~certain circumstances set forth in Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm the Proposed Plan even if it has not been accepted by all impaired classes of claims and ~~Sales~~equity ~~Cycle~~interests. The precise requirements and evidentiary showing for confirming a Plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class (i.e., unsecured or secured claims, subordinated or senior claims). Generally, with respect to equity shares, a Plan may be “crammed down” even if the shareholders receive no recovery if the proponent of the Plan demonstrates that (1) no class junior to the equity shares are receiving or retaining property under the Plan and (2) no class of claims or interests senior to the equity shares are being paid more than in full.

~~Revenue~~Sale from operations is derived from sales of natural gas, NGL and condensate products produced by our well properties for which we are the operator. A de minimis percentage of revenue is also earned from either working interests, royalty interests, or small override interests we hold in various non-operated well properties. Our sales revenue is generated from on-going daily or monthly sales of volumes of gas and oil commodities, the sales volumes determined by metering or other measurement methods at the delivery point when control of the commodities transfers to the customer. Process

~~Revenue~~On ~~Recognition~~June –1, ~~Contracts~~2018, the Rex Debtors filed with ~~Customers~~the Bankruptcy Court a Motion For Orders Pursuant To Section 363 of the Bankruptcy Code: (I)(A) Approving Bidding Procedures For The Sale Of The Debtors’ Assets, (B) Scheduling An Auction And Approving The Form And Manner Of Notice Thereof, (C) Approving Assumption And Assignment Procedures and (D) Scheduling A Sale Hearing And Approving The Form And Manner Of Notice Thereof; (II)(A) Approving The Sale Of The Debtors’ Assets Free And Clear Of Liens, Claims, Interests And Encumbrances and (B) Approving The Assumption And Assignment Of Executory Contracts And Unexpired Leases; and (III) Granting Related Relief. On June 29, 2018, the Bankruptcy Court entered an order approving the bidding procedures and scheduling the auction.

We ~~recognize~~have ~~sales~~been ofin ~~our~~discussions ~~natural~~with ~~gas,~~various ~~NGL~~third ~~and~~parties ~~condensate~~who ~~products~~may ~~when~~be ~~control~~interested ofin ~~the~~purchasing ~~product~~some isor ~~transferred~~all toof the ~~customer~~assets atof ~~delivery~~the ~~points~~Rex ~~specified~~Debtors inthrough ~~each~~the ~~commodity~~bankruptcy ~~purchase~~process, ~~contract.~~either ~~Under~~through ~~our~~a ~~commodity~~sale ~~sales~~pursuant ~~contracts,~~to ~~the~~Section ~~delivery~~363 of ~~each~~Chapter ~~unit~~11 of ~~natural~~the ~~gas,~~Bankruptcy ~~NGLs~~Code or ~~condensate represents a separate performance obligation, and revenue is recognized at the point~~ in ~~time~~connection ~~when~~with the ~~performance~~Proposed ~~obligations are fulfilled~~Plan. ~~There~~At ~~are~~this notime, ~~significant~~it ~~financing~~is ~~components~~not ~~associated~~possible ~~with our revenues from sales~~ to ~~customers~~predict asaccurately ~~payment terms are typically within 30 to 60 days of control transfer. Sales revenue recognized corresponds directly with~~ the ~~value~~effect ~~to the customer~~ of the ~~Company’s~~Chapter ~~performance~~11 ~~completed~~reorganization toprocess ~~date.~~on ~~We record revenue from sales of~~ our ~~natural gas~~business, ~~NGL~~creditors ~~and~~or ~~condensate~~stockholders, ~~production~~when in the ~~amount~~Rex ~~equal~~Debtors tomay ~~our~~emerge ~~net revenue interest in sales~~ from ~~the~~Chapter ~~producing~~11 ~~properties.~~or ~~Under~~what ~~ASC 606,~~ the ~~Company~~disposition ~~recognizes~~will ~~revenues~~be ~~based on a determination~~ of ~~when~~any ~~control~~claims ofagainst ~~its~~the ~~commodities~~Rex ~~is transferred and whether it is acting as a principal or agent in certain transactions~~Debtors. ~~All~~ ~~facts~~Our ~~and~~future ~~circumstances~~results ofdepend anon ~~arrangement~~the ~~are~~timely ~~considered~~ and ~~judgment~~successful isconfirmation often required in making this determination. The Company considers risk of loss an important indicator of when control transfers, which is comprised of risks associated with loss of product during processing. The Company concluded that title, custody, and ~~acceptance~~implementation ~~are not by themselves determinative indicators~~ of ~~control, as such factors may be present in~~ the ~~case~~Proposed ~~of a sale or the performance of a service~~Plan.

AsCopies ~~a result~~ of ~~this~~all ~~analysis,~~court ~~the~~filings ~~Company~~made ~~concluded~~in ~~that~~our ~~the~~Chapter ~~Company~~11 ~~represents~~cases ~~the~~are ~~principal~~available ~~and~~from ~~the~~Prime ~~ultimate third party is its customer~~Clerk, ~~which~~Claims ~~implies~~and ~~that~~Noticing ~~the~~Agent ~~Company~~for ~~maintains control of~~ the ~~product~~bankruptcy ~~through the tailgate of gas processing plants in certain natural gas processing in accordance with the control model in ASC 606. As a result~~proceedings, ~~there~~at ~~were no changes to the Company’s presentation of revenues and expenses for these agreements~~https://cases.primeclerk.com/rexenergy/Home-Index.

~~Pricing~~Magnitude of ~~Commodity~~Potential ~~Sales~~Claims

~~Our~~On ~~natural~~July ~~gas~~2, ~~production~~2018, isthe ~~primarily~~Rex ~~sold~~Debtors ~~under~~filed ~~contracts~~with ~~that~~the ~~are~~Bankruptcy ~~typically~~Court ~~priced~~schedules atand astatements ~~differential~~setting toforth, ~~published~~among ~~commodity~~other ~~index~~things, ~~prices~~the ~~for~~assets and liabilities of the ~~producing~~Rex ~~area~~Debtors, ~~due~~subject to the ~~natural~~assumptions ~~gas~~filed ~~quality~~in ~~and~~connection therewith. On August 1, 2018, the ~~proximity~~Debtors tofiled ~~major~~amended ~~consuming~~schedules ~~markets~~and statements. The ~~NGL~~schedules and ~~condensate~~statements ~~production~~may isbe ~~sold~~subject ~~under~~to ~~contract~~further ~~pricing~~amendment ~~referenced~~or modification after filing. Holders of prepetition claims will be required to ~~various~~file ~~liquids~~proofs ~~commodity~~of ~~index~~claims ~~prices~~by the applicable deadline for filing certain proofs of claims in the Rex Debtors’ Chapter 11 cases. ~~All~~The ~~revenue~~court ~~from~~has ~~production~~set isAugust ~~generated~~6, ~~from~~2018 ~~our~~as ~~operations~~the bar date for filing of general claims, and November 14, 2018 as the bar date for filing of governmental claims. Differences between amounts scheduled by the Rex Debtors and claims by creditors will be investigated and resolved in connection with the ~~Appalachian~~claims ~~Basin~~resolution process.

Production Imbalances

The Company uses the sales method to account for natural gas production imbalances. If the Company’s sales volume for a well exceeds the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Contract Balances

Under the Company’s product sales contracts, its customers are invoiced once the Company’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to material contract assets or contract liabilities.

Performance Obligations

~~sales~~Liabilities ~~contracts~~Subject ~~are established~~ to facilitate on-going sales of our products with our customers over the term of the contract, with pricing and delivery terms identified in each contract. We do not have contracts with customers that describe the performance obligation in terms of a defined gross total delivery volume over time. We utilized the practical expedient in ASC 606-10-50-14(A) which states that disclosure of the portion of a transaction price allocated to remaining performance obligations is not required if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, each unit of product generally represents a separate performance obligation; therefore future sales volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.Compromise

AsOur ofconsolidated ~~March~~balance 31sheet includes amounts classified as “Liabilities Subject to Compromise,” ~~2018~~which ~~and~~represent ~~December~~prepetition 31liabilities that have been allowed, ~~2017~~or that we anticipate will be allowed, as claims in our Chapter 11 cases. The amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities we ~~had~~have ~~trade~~estimated ~~receivable~~and ~~balances~~the ~~related~~claims filed, or to ~~revenue~~be ~~from~~filed, ~~contracts~~will be investigated and resolved in connection with ~~customers~~the ofclaims ~~approximately~~resolution ~~$19~~process.6 ~~million~~We will continue to evaluate these liabilities throughout the Chapter 11 process and ~~$21~~adjust amounts as necessary.7 ~~million,~~Such ~~respectively~~adjustments may be material. The following table summarizes the components of liabilities subject to compromise included on the condensed consolidated balance sheet:

The following table summarizes our disaggregated revenues recognized from contracts with customers in our Consolidated Statements of Operations for the three month periods ended March 31, 2018 and 2017.

	June 30, 2018 (in thousands)
Accounts Payable and Accrued Expenses	$	27,716
Accrued Interest Payable		30,043
Debt (See Note 8)		609,865
Liabilities Subject to Compromise	$	667,624

	Three Months Ended March 31,
($ in Thousands)	2018		2017
Revenues from Contracts with Customers by Product
Natural Gas	$	28,576	$	29,633
NGLs		28,704		17,761
Condensate		6,612		3,409
Total	$	63,892	$	50,803

Reorganization Items, Net

4We have incurred and are expected to continue to incur significant costs associated with the reorganization. ~~BUSINESS~~These ~~AND~~costs, ~~OIL~~which ~~AND~~are ~~GAS~~expensed ~~PROPERTY~~as ~~DISPOSITIONS~~incurred, are expected to significantly affect our results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined. The following table summarizes the components of reorganization items included on the consolidated statements of operations:

Benefit Street Partners, LLC

	Three and Six Months Ended June 30, 2018 (in thousands)
Legal and Professional Fees	$	(9,817	)
Unamortized Deferred Financing Balances (a)		43,509
Debtor-in Possession Financing Fees		(3,750	)
Effect of Early Hedge Terminations		(1,175	)
Other		(132	)
Reorganization Items, net	$	28,635

~~On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC~~ (~~“BSP”~~a) toAcceleration ~~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~~deferred ~~estimated~~gains ~~well~~on ~~costs~~debt ~~for 16 designated wells in Butler County~~restructurings, ~~Pennsylvania,~~deferred ~~all~~financing ~~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~~unamortized ~~for~~net bydiscounts ~~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~~debt ~~designated~~instruments ~~wells~~previously inaccounted ~~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 oftroubled ~~March 31,~~debt ~~2018.~~restructurings ~~BSP~~pursuant has paid for its interest in the elected wells as of December 31, 2017, and no additional elections have occurred during the quarter ended March 31, 2018. The remainder of the proceeds may be received if BSP makes additional elections as additional wells are drilled to ~~total~~ASC ~~depth or placed in sales. BSP earns an assignment of 15%~~470-~~20% working interest in acreage located within each of the units in which it participates. As of March 31~~60, ~~2018,~~Troubled ~~all~~Debt 45Restructurings ~~committed~~by ~~wells were in line and producing~~Debtors.

~~The~~Effect ~~BSP transaction constitutes a pooling~~ of ~~assets~~Filing 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~~Creditors ~~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.~~Shareholders

~~Sale~~Subject to certain exceptions, under the Bankruptcy Code, the filing of ~~Warrior~~Bankruptcy ~~South~~Petitions ~~Assets~~automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Rex Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Rex Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Creditors are stayed from taking any actions against the Rex Debtors as a result of defaults on the Rex Debtors’ debt obligations (which defaults were triggered prior to or by the filing of Bankruptcy Petitions), subject to certain limited exceptions permitted by the Bankruptcy Code. We did not record interest expense on our 1%/8% senior secured second lien notes (“Second Lien Notes”) or our unsecured 6.25% Senior Notes due 2022 and unsecured 8.875% Senior Notes due 2020 (the “Unsecured Notes”) for the period from May 18, 2018 (Petition Date), through June 30, 2018. For that period, contractual interest on the Second Lien Notes and the Unsecured Notes was approximately $5.7 million.

~~On January 11~~Generally, ~~2017,~~under ~~we,~~the ~~together~~Bankruptcy ~~with MFC Drilling~~Code, ~~Inc.,~~prepetition liabilities and ~~ABARTA~~post-petition ~~Oil~~liabilities &must ~~Gas~~be ~~Co.,~~satisfied ~~Inc.~~in ~~sold~~full ~~substantially~~before ~~all~~the holders of our ~~jointly~~existing ~~owned~~common ~~oil~~ and ~~gas~~preferred ~~interests~~shares inare ~~Noble,~~entitled ~~Guernsey, and Belmont Counties, Ohio,~~ to ~~Antero~~receive ~~Resources~~any ~~Corporation.~~settlement ~~These~~or ~~interests~~retain ~~comprised~~any ~~our~~property ~~Warrior~~under ~~South~~a ~~development area~~Plan. The ~~effective~~ultimate ~~date~~recovery ~~for~~to ~~the~~creditors ~~transaction~~and/or ~~is October 1~~shareholders, ~~2016.~~if ~~The sales agreement includes representations~~any, ~~warranties,~~will ~~covenants~~not ~~and~~be ~~agreements~~determined asuntil ~~well~~confirmation ~~as various provisions for purchase price~~ and ~~post-closing~~implementation ~~adjustments customary for transactions~~ of ~~this~~one ~~type.~~or ~~Total~~more ~~consideration for the transaction was approximately $50~~Plans.0 ~~million,~~No ~~with~~assurance ~~approximately~~can ~~$29.1~~be ~~million~~given ~~net~~as to uswhat values, ~~subject~~if ~~to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11~~any, ~~2017. Approximately~~will ~~$5.0~~be ~~million~~ascribed ofin the ~~total~~Chapter 11 ~~proceeds~~proceedings ~~due~~ to useach ~~was held in escrow and released to us in December 2017 . The sale~~ of ~~assets~~these ~~resulted~~constituencies inor awhat ~~gain~~types onor ~~disposal~~amounts of ~~assets~~settlements, ofif ~~approximately~~any, ~~$1.8~~they ~~million~~will ~~in January 2017~~receive. ~~This~~A ~~gain~~Plan ~~includes~~could ~~the~~result ~~additional proceeds held~~ in ~~escrow.~~holders ~~The sale~~ of ~~assets~~the ~~included~~Rex 14Debtors’ ~~gross~~liabilities ~~wells~~and/or ~~with~~equity ~~associated~~shares ~~production~~receiving ofno 15settlement ~~Mmcfe/d,~~on ~~with~~account 9of ~~Mmcfe/d~~their ~~net~~interests ~~to us,~~ and ~~approximately~~cancellation ~~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 amounts outstanding under our prior revolving line~~ of ~~credit~~their ~~and for general corporate purposes~~holdings.

~~Sale~~Appointment of ~~Westmoreland~~Creditors ~~Assets~~Committee

On ~~March 13~~May 29, 2018, the ~~Company,~~Bankruptcy ~~entered~~Court ~~into~~appointed athe ~~Purchase~~official ~~and~~committee ~~Sale~~for ~~Agreement~~unsecured ~~with~~creditors ~~XPR Resources, LLC~~ (the “~~XPR~~UCC”),. ~~pursuant~~The toUCC ~~which~~and ~~the Company agreed to sell to XPR certain of~~ its ~~non-operated~~legal ~~oil~~representatives ~~and~~have ~~gas~~a ~~interests~~right ~~in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core~~ to ~~the~~be ~~Company. In~~heard ~~a related transaction, the Company entered into a Membership Interest Purchase Agreement~~ on ~~the~~all ~~same~~matters ~~date~~that ~~with~~come ~~COG2,~~before ~~LLC (“COG2”), an affiliate of XPR, pursuant to which~~ the ~~Company~~Bankruptcy ~~agreed~~Court ~~to sell to COG2 its 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018,~~ with anrespect ~~effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject~~ to ~~customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018, prior to closing adjustments. Approximately $0.2 million of~~ the ~~total~~Rex ~~proceeds due to us is being held in escrow~~Debtors. ~~The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.~~

5.Rejection ~~RECENTLY~~of ~~ISSUED~~Executory ~~ACCOUNTING PRONOUNCEMENTS~~Contracts

InSubject ~~May~~to ~~2014~~certain exceptions, under the ~~Financial~~Bankruptcy ~~Accounting~~Code, ~~Standards~~the ~~Board~~Rex (Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the ~~“FASB”)~~approval ~~issued~~of ~~ASU~~the ~~2014-09,~~Bankruptcy ~~Revenue~~Court ~~from~~and ~~Contracts~~satisfaction ~~with~~of ~~Customers~~certain other conditions. ~~The~~Generally, ~~amendments~~the inrejection ~~this~~of ~~ASU~~an ~~affect~~executory ~~any~~contract ~~entity~~or ~~using~~unexpired ~~U.S.~~lease ~~GAAP~~is ~~that~~treated ~~either~~as ~~enters~~a ~~into~~prepetition ~~contracts~~breach ~~with~~of ~~customers~~such executory contract or unexpired lease and, subject to ~~transfer~~certain ~~goods~~exceptions, relieves the Rex Debtors of performing their future obligations under such executory contract or ~~services~~unexpired lease but entitles the contract counterparty or ~~enters~~lessor ~~into~~to ~~contracts~~a prepetition general unsecured claim for ~~the~~damages ~~transfer~~caused ofby ~~nonfinancial~~such ~~assets~~deemed ~~unless~~breach. ~~those~~Counterparties to such rejected contracts ~~are~~or ~~within~~leases may assert unsecured claims in the ~~scope~~Bankruptcy ofCourt ~~other~~against ~~standards~~the applicable Rex Debtor’s estate for damages. ~~This~~Generally, ~~ASU~~the ~~will~~assumption ~~supersede~~of an executory contract or unexpired lease requires the ~~revenue~~Rex ~~recognition~~Debtors ~~requirements~~to incure ~~Topic~~existing ~~605,~~monetary ~~Revenue~~defaults ~~Recognition,~~under such executory contract or unexpired lease and ~~most~~provide ~~industry-specific~~adequate ~~guidance~~assurance of future performance. ~~The~~Accordingly, ~~core~~any ~~principle~~description of an executory contract or unexpired lease with any of the ~~guidance~~Rex Debtors in ~~ASU~~this ~~2014~~Quarterly Report on Form 10-09Q, isincluding ~~that~~where anapplicable ~~entity~~a ~~should~~quantification ~~recognize~~of ~~revenue~~our toobligations ~~depict~~under any such executory contract or unexpired lease with the ~~transfer~~applicable ofRex ~~promised~~Debtor, ~~goods~~is orqualified ~~services~~by toany ~~customers~~overriding inrejection anrights ~~amount~~we ~~that~~have ~~reflects~~under the ~~consideration~~Bankruptcy toCode. ~~which~~Further, ~~the~~nothing ~~entity~~herein ~~expects~~is toor shall be ~~entitled~~deemed inan ~~exchange~~admission ~~for~~with ~~those~~respect ~~goods~~to orany ~~services.~~claim ~~The~~amounts ~~guidance~~or ~~provides~~calculations aarising ~~five~~from ~~step~~the ~~process~~rejection toof beany ~~applied~~executory incontract ~~evaluating~~or ~~contracts~~unexpired ~~under~~lease and the ~~new~~Rex ~~standard:~~Debtors expressly preserve all of their rights with respect thereto.

1)Covenant ~~Identify the contract(s) with a customer.~~Violations

2)Our ~~Identify~~filing of the ~~performance~~Bankruptcy Petitions constituted an event of default under our Term Loan Credit Facility, and the indentures governing the Second Lien Notes and the Unsecured Notes, which resulted in automatic acceleration of our obligations under those instruments. However, our outstanding obligations under the Term Loan Credit Facility and the indentures governing the Unsecured Notes were accelerated prior to the Petition Date. In addition to the non-payment of second lien interest, we also encountered additional events of default related to certain non-financial covenants associated with our term loan agreement. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited quarterly financial statements for the quarter ended December 31, 2017 and our annual audited financial statements for the year ended December 31, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and written notices of the events of default in a subsequent draw request under the ~~contract~~term loan agreement. Additionally, other events of default have occurred, including the receipt of a going concern explanatory paragraph from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2017. We received a notice of acceleration on April 27, 2018, from the lenders under our term loan agreement demanding immediate payment of all outstanding notes and loans, together with all accrued interest, fees, yield maintenance and call protection amounts. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us as a result of an event of default. See Note 8 “Debt” for additional details regarding our debt.

3)Ability ~~Determine~~to ~~the~~Continue ~~transaction~~as ~~price.~~a Going Concern

4)The ~~Allocate~~significant risks and uncertainties related to our covenant violations, liquidity and Chapter 11 proceedings described above raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the ~~transaction~~normal ~~price~~course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the ~~performance~~carrying ~~obligations~~values inand classification of our assets and liabilities and the ~~contract~~reported amounts of income and expenses could be required and could be material.

5)3. ~~Recognize~~RECENTLY ~~revenue~~ISSUED ~~when~~ACCOUNTING ~~(or as) the entity satisfies a performance obligation.~~PRONOUNCEMENTS

~~Subsequent~~In toFebruary 2016, the ~~issuance~~Financial ofAccounting ~~ASU~~Standards ~~2014-09,~~Board ~~the~~ (“FASB”) issued ~~several additional~~ Accounting Standards ~~Updates~~Update to(“ASU”) ~~clarify implementation guidance~~2016-02, ~~provide guidance regarding principal vs~~Leases. ~~agent~~Under ~~considerations~~the ~~and~~new ~~identifying performance obligations~~guidance, ~~provide~~lessees ~~narrow-scope~~will ~~improvements,~~be ~~and provide additional disclosure guidance. ASU 2014-09 is~~ required to berecognize ~~adopted using either~~ the ~~full~~following ~~retrospective~~for ~~approach, with~~ all ~~prior~~leases ~~periods presented adjusted, or the modified retrospective approach,~~ (with the ~~cumulative~~exception ~~effect~~ of ~~applying~~short-term ~~the~~leases) ~~new~~at ~~standard recognized as an adjustment to retained earnings in~~ the ~~most~~commencement current period presented in the financial statements. The standard is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2017. We adopted the new standard effective January 1, 2018 using a modified retrospective approach. We did not require a cumulative adjustment to retained earnings as a result of adopting the standard. date:

In• ~~February~~a ~~2016,~~lease ~~the FASB issued ASU 2016-02~~liability, ~~Leases.~~which ~~Under~~is ~~the~~a ~~new~~lessee’s ~~guidance,~~obligation ~~lessees will be required~~ to ~~recognize~~make ~~the~~lease ~~following~~payments ~~for~~arising ~~all~~from ~~leases~~a ~~(with~~lease, ~~the~~measured ~~exception~~on ofa ~~short-term~~discounted ~~leases)~~basis; ~~at the commencement date:~~and

• Aa ~~lease~~right-of-use ~~liability~~asset, which is aan asset that represents the lessee’s ~~obligation~~right to ~~make~~use, ~~lease~~or ~~payments~~control ~~arising~~the ~~from~~use ~~a lease~~of, ~~measured~~a onspecified aasset ~~discounted~~for ~~basis;~~the ~~and~~lease term.

~~• 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.~~13

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. We adopted this standard effective January 1, 2018 on a retrospective basis. Adoption of the standard did not have an impact on the presentation of our consolidated statements of cash flows

In May 2017, the FASB issued ASU 2017-09, Stock Compensation - Scope of Modification Accounting, which provides guidance about the types of changes to terms or conditions of a share-based payment award that would require an entity to apply modification accounting. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments in this update should be applied prospectively to awards modified on or after the adoption date. We adopted this standard effective January 1, 2018. Adoption of the standard did not have a material impact on our consolidated financial statements.

64. ~~CONCENTRATIONS~~REVENUE ~~OF CREDIT RISK~~ RECOGNITION

ByEffective ~~using~~January ~~derivative~~1, ~~instruments~~2018, towe ~~hedge~~adopted ~~exposure~~Accounting toStandards ~~changes~~Codification in(“ASC”) ~~commodity~~606, ~~prices~~“Revenue from Contracts with Customers,” weusing ~~are~~the ~~exposed~~modified toretrospective ~~credit~~method ~~risk~~applied ~~and~~to ~~market~~those ~~risk.~~contracts ~~Credit~~which ~~risk~~were isnot ~~the~~completed ~~failure~~as of January 1, 2018. Under the ~~counterparties~~modified toretrospective ~~perform~~method, ~~under~~we recognized the ~~terms~~cumulative effect of initially applying the ~~derivative~~new ~~contract.~~revenue ~~When~~standard ~~the~~as ~~fair~~an ~~value~~adjustment ofto the ~~derivative~~opening isbalance ~~positive,~~of ~~the~~retained ~~counterparty~~earnings; ~~owes us~~however, ~~which~~no ~~creates~~material ~~repayment~~adjustment ~~risk.~~was Werequired ~~minimize~~as ~~the~~a ~~credit~~result orof ~~repayment~~adopting ~~risk~~ASC in606. ~~derivative~~Results ~~instruments~~for byreporting ~~entering~~periods ~~into~~beginning ~~transactions~~on ~~with~~January ~~high-quality~~1, ~~counterparties.~~2018 ~~Our~~are ~~counterparties~~presented ~~are~~under ~~investment~~the ~~grade~~new ~~financial~~revenue ~~institutions~~standard. ~~(see~~The ~~Note~~comparative 7,information ~~Long-Term~~has ~~Debt,~~not tobeen ~~our~~restated ~~Consolidated~~and ~~Financial~~continues ~~Statements).~~to Webe ~~have~~reported aunder ~~master~~the ~~netting~~accounting ~~agreement~~standards in ~~place~~effect ~~with~~for ~~our~~those ~~counterparties~~periods. ~~that~~We ~~provides~~performed ~~for~~an analysis of the ~~offsetting~~impact of ~~payables~~adopting ~~against~~ASC ~~receivables~~606 ~~from~~across ~~separate~~all ~~derivative~~revenue ~~contracts.~~streams ~~None~~and ofdid ~~our~~not ~~derivative~~identify ~~contracts~~any ~~have~~changes ato ~~collateral~~its ~~provision~~revenue recognition policies that would ~~require~~result ~~funding~~in ~~prior~~a tomaterial ~~the~~impact ~~scheduled~~to ~~cash~~its ~~settlement~~consolidated ~~date~~financial statements. ~~For~~We ~~additional~~also ~~information,~~implemented ~~see~~processes ~~Note~~and 8,controls ~~Derivative~~to ~~Instruments~~ensure ~~and~~new ~~Fair~~contracts ~~Value~~are ~~Measurements,~~reviewed for the appropriate accounting treatment and to ~~our~~generate ~~Consolidated~~the ~~Financial~~required ~~Statements.~~disclosures under the standards.

WeRevenues ~~depend~~Sources on a relatively small number of purchasers for a substantial portion of our revenue. For the three months ended March 31, 2018, approximately 97.8% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 60.1% of commodity sales. We believe the growth in our Appalachian estimated proved reserves, as well as the quantity of purchasers, will help us to minimize our future risks by diversifying our ratio of condensate and ~~gas~~Sales ~~sales.~~ Cycle

7Revenue from operations is derived from sales of natural gas, NGL and condensate products produced by our well properties for which we are the operator. ~~LONG~~A de minimis percentage of revenue is also earned from either working interests, royalty interests, or small override interests we hold in various non-~~TERM~~operated ~~DEBT~~well properties. Our sales revenue is generated from on-going daily or monthly sales of volumes of gas and oil commodities, the sales volumes determined by metering or other measurement methods at the delivery point when control of the commodities transfers to the customer.

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, 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 prior amended and restated senior secured revolving credit agreement with Royal Bank of Canada, as Administrative Agent, and the lenders from time to time party thereto (the “Prior 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 to refinance the loans then outstanding under the Prior 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 were initially limited to $300,000,000. Amounts borrowed and repaid may not be re-borrowed. Unless accelerated pursuant to the terms of the Term Loan, 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 our 1.00/8.00% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) unless less than $25,000,000 in aggregate principal amount of Second Lien Notes are then outstanding and no Event of Default (as defined in the Term Loan) exists on such date. Except as otherwise provided under the terms of the Term Loan in the case of an occurrence of an event of default, 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~~Revenue ~~lender~~Recognition ~~consent)~~– ~~and~~Contracts ~~(b)~~with the date upon which we terminate such commitments. As of March 31, 2018, we had $221.0 million in borrowings outstanding and approximately $32.0 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. We incurred an additional $2.3 million in OID related to the Delayed Draw Term Facility. During the three months ended March 31, 2018, we amortized $0.3 million of debt issuance costs and $0.5 million of OID. The amortization of debt issuance costs and OID are reported as Interest Expense in our Consolidated Statement of Operations.Customers

AtWe ~~March~~recognize ~~31,~~sales ~~2018~~of our natural gas, ~~approximately~~NGL ~~$7.7~~and ~~million~~condensate products when control of the product is transferred to the customer at delivery points specified in ~~deferred~~each ~~financing~~commodity ~~fees~~purchase contract. Under our commodity sales contracts, the delivery of each unit of natural gas, NGLs or condensate represents a separate performance obligation, and ~~OID~~revenue ~~were~~is ~~written~~recognized ~~off~~at ~~related~~the topoint in time when the performance obligations are fulfilled. There are no significant financing components associated with our ~~Term~~revenues ~~Loan~~from ~~due~~sales to ~~(i)~~customers ~~the~~as ~~uncertainty~~payment ~~regarding~~terms ~~the~~are ~~Company’s~~typically ~~ability~~within 30 to ~~cure~~60 ~~the~~days ~~default~~of ascontrol ~~discussed~~transfer. inSales ~~Note~~revenue 1,recognized ~~(ii)~~corresponds directly with the value to the customer of our ~~inability~~performance completed to ~~comply~~date. ~~with~~We ~~certain~~record ~~financial~~revenue ~~covenants~~from ~~contained~~sales inof our ~~Term~~natural ~~Loan~~gas, NGL and ~~(iii)~~condensate production in the ~~acceleration~~amount ~~notice~~equal ~~received~~to ~~from~~our ~~the~~net revenue interest in sales from the ~~lenders~~producing ~~the~~properties. ~~Term~~Under ~~Loan~~ASC 606, we recognize revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions. All ~~The~~facts ~~amount~~and ~~written~~circumstances ~~off~~of an arrangement are considered and judgment is ~~included~~often required in ~~interest~~making ~~expense~~this ondetermination. ~~the~~We ~~consolidated~~consider ~~statements~~risk of ~~operations~~loss ~~for~~an ~~the~~important ~~period~~indicator ~~ended~~of ~~March~~when 31control transfers, ~~2018~~which is comprised of risks associated with loss of product during processing. We concluded that title, custody, and acceptance are not by themselves determinative indicators of control, as such factors may be present in the case of a sale or the performance of a service.

~~Borrowings~~As ~~under~~a ~~the~~result ~~Term~~of ~~Loan~~this ~~bear~~analysis, ~~interest~~we atconcluded athat ~~rate~~the ~~per~~Company ~~annum~~represents ~~equal to~~ the ~~“Adjusted~~principal ~~LIBO~~and ~~Rate”~~the ~~(subject~~ultimate tothird aparty ~~1.00% floor) plus an 8.75% per annum margin. The “Adjusted LIBO Rate”~~ is ~~equal~~its tocustomer, ~~the~~which ~~product~~implies ofthat the ~~three~~Company ~~month~~maintains ~~LIBOR~~control ~~rate~~of ~~multiplied by~~ the ~~statutory~~product ~~reserve~~through ~~rate. Upon~~ the ~~occurrence~~tailgate ~~and continuance~~ of angas ~~Event~~processing ofplants ~~Default~~in ~~all~~certain ~~outstanding~~natural ~~loans~~gas ~~bear~~processing ~~interest~~in ataccordance awith ~~rate equal to 4.00% per annum plus~~ the ~~then-effective~~control ~~rate~~model ofin ~~interest.~~ASC ~~Interest is payable on the last business day of each March, June, September and December~~606. ~~Under~~ ~~the~~As ~~Term~~a ~~Loan~~result, wethere ~~will~~were ~~pay~~no achanges ~~3.5%~~to ~~commitment~~our ~~fee~~presentation ~~on any unused portion~~ of ~~the~~revenues ~~Delayed~~and ~~Draw~~expenses ~~Term~~for ~~Facility~~these agreements.

~~The~~Pricing ~~Term Loan requires us to prepay the loans with 100%~~ of ~~the~~Commodity 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 (“excess cash flow” as defined in the Term Loan agreement represents EBITDAX less capital expenditures, cash payments for interest, cash payments for income taxes, and adjustments for certain non-cash expenses) are required until no more than $287,950,000 in aggregate principal amount of 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 one 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. Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at March 31, 2018 they have been recorded at their fair value using Level 2 inputs. For the three months ended March 31, 2018, we recorded a fair value liability of approximately $53.0 million as Short-Term Derivative Instruments on our Consolidated Balance Sheet. For the three months ended March 31, 2018, we recorded a loss of approximately $53.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which have led to the Company deciding to file Chapter 11 Bankruptcy which have caused these amounts to become due and payable. As of December 31, 2017, the fair value of these embedded derivatives was not material.Sales

~~The~~Our ~~Term~~natural ~~Loan~~gas ~~contains~~production ~~covenants~~is primarily sold under contracts that ~~restrict~~are ~~our~~typically ~~ability~~priced at a differential to, ~~among~~published ~~other~~commodity ~~things,~~index ~~materially~~prices ~~change~~for the ~~nature~~producing ofarea ~~our~~due ~~business,~~to ~~make~~the ~~dividend~~natural ~~payments,~~gas ~~enter~~quality ~~into~~and ~~transactions~~the ~~with~~proximity ~~affiliates,~~to ~~create~~major orconsuming ~~acquire~~markets. ~~additional~~NGL ~~subsidiaries,~~and ~~incur~~condensate ~~indebtedness,~~production ~~sell~~is ~~assets,~~sold ~~make~~under ~~loans~~contract pricing referenced to ~~others,~~various ~~make~~liquids ~~investments,~~commodity ~~enter~~index ~~into~~prices. ~~mergers,~~All ~~incur~~revenue ~~liens,~~from ~~and~~production ~~enter~~is ~~into~~generated ~~agreements~~from ~~regarding~~our ~~swap~~operations ~~and~~in ~~other~~the ~~derivative~~Appalachian ~~transactions~~Basin.

~~The~~Production 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; and (3) as of the last day of any fiscal quarter ending on or after September 30, 2017 the 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 December 31, 2017 and (ii) 1.30 to 1.00 for each fiscal quarter thereafter. As of March 31, 2018, our PDP Coverage Ratio was 2.34 to 1.00, Net Senior Secured Debt to EBITDAX Ratio was 2.92 to 1.00 and EBITDAX to Cash Interest Expense was 2.51 to 1.00.Imbalances

~~Our~~We ~~obligations~~use ~~under~~ the ~~Credit~~sales ~~Agreement~~method ~~have~~to ~~been~~account ~~accelerated~~for ~~upon~~natural ~~the~~gas ~~occurrence~~production ofimbalances. If anour ~~Event~~sales volume for a well exceeds our proportionate share of ~~Default~~production ~~(as~~from ~~such~~the ~~term~~well, a liability is ~~defined~~recognized into the ~~Term~~extent ~~Loan).~~that ~~See~~our ~~Note~~share 1,of ~~Basis~~estimated ofremaining ~~Presentation~~recoverable ~~and~~reserves ~~Principles~~from ofthe ~~Consolidation~~well ~~and~~is ~~Note~~insufficient 18to ~~Subsequent~~satisfy ~~Events,~~this imbalance. No receivables are recorded for ~~additional~~those ~~information~~wells on ~~certain~~which ~~financial~~we ~~and~~have ~~non-financial~~taken ~~covenant~~less ~~defaults~~than ~~that~~our ~~have~~proportionate ~~occurred~~share of production.

Contract Balances

Under our product sales contracts, our customers are invoiced once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities.

Performance Obligations

Our contracts with customers represent a series of performance obligations satisfied over time when a performance obligation is satisfied by the transfer of control over a product to the customer. The transfer of control is generally considered to occur when we have transferred custody, title, risk of loss and relinquished any repurchase rights or other similar rights. Our commodity sales contracts are established to facilitate on-going sales of our products with our customers over the term of the contract, with pricing and delivery terms identified in each contract. We do not have contracts with customers that describe the performance obligation in terms of a defined gross total delivery volume over time. We utilized the practical expedient in ASC 606-10-50-14(A) which states that disclosure of the portion of a transaction price allocated to remaining performance obligations is not required if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, each unit of product generally represents a separate performance obligation; therefore future sales volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

As of June 30, 2018 and December 31, 2017, we had trade receivable balances related to revenue from contracts with customers of approximately $25.9 million and $21.7 million, respectively.

~~Obligations~~The ~~under~~following ~~the~~table ~~Term~~summarizes ~~Loan are secured by mortgages on~~ our ~~oil~~disaggregated ~~and~~revenues ~~gas~~recognized ~~properties.~~from Incontracts ~~connection~~ with ~~the~~customers ~~Term~~in ~~Loan, we, including~~ our ~~wholly~~Consolidated ~~owned~~Statements 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~~Operations ~~28, 2017, in favor of the Collateral Agent~~ for the ~~lenders~~three ~~from time to time party to the Term Loan, the secured swap parties~~ and ~~the~~six ~~Issuing~~month ~~Bank~~periods ~~(the~~ended ~~“Guaranty and Collateral Agreement”). Pursuant to the Guaranty and Collateral Agreement~~June 30, ~~each~~2018 ~~of the Guarantors, jointly~~ and ~~severally, guaranteed the prompt and complete payment of our obligations under the Term Loan~~2017. 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 Notes

	Three Months Ended June 30,				Six Months Ended June 30,
($ in Thousands)	2018		2017		2018		2017
Revenues from Contracts with Customers by Product
Natural Gas	$	29,705	$	29,097	$	59,387	$	60,442
NGLs		32,293		15,367		61,011		32,667
Condensate		13,157		2,993		19,782		6,413
Total	$	75,155	$	47,457	$	140,180	$	99,522

~~On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8~~5.~~875%~~ ~~Senior~~OIL ~~Notes~~AND ~~due~~GAS ~~2020~~PROPERTIES ~~(the~~– ~~“2020~~JOINT ~~Notes”)~~VENTURES ~~and~~AND ~~6.25%~~DIVESTITURES 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 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 Second Lien 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.

InBenefit ~~exchange~~Street ~~for $324.0 million in aggregate principal amount of the 2020 Notes~~Partners, 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 Second Lien 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 Second Lien 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 Second Lien Notes bore interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and have borne interest at a rate of 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.LLC

~~The~~On ~~Company~~March ~~has~~1, ~~not~~2016, ~~made~~we ~~the~~entered ~~semi-annual~~into ~~interest~~a ~~payment~~joint toexploration ~~the~~and ~~holders~~development agreement with an affiliate of ~~our~~Benefit ~~Second~~Street ~~Lien~~Partners, ~~Notes~~LLC ~~that~~(“BSP”) ~~was~~to ~~due~~jointly ondevelop ~~April~~58 2,specifically ~~2018,~~designated ~~and~~wells ~~did~~in ~~not~~our ~~make~~Moraine ~~the~~East ~~interest~~and ~~payment~~Warrior ~~prior~~North operated areas. BSP agreed to ~~the~~participate ~~expiration~~in and fund 15.0% of the 30estimated ~~day~~well ~~grace~~costs ~~period. Therefore,~~for ~~the~~16 ~~maturity~~designated ~~date~~wells in Butler County, Pennsylvania, all of ~~the~~which ~~Second~~have ~~Lien~~already ~~Notes~~been isdrilled, ~~upon~~completed, ~~requisite~~placed ~~notice,~~in ~~subject~~sales toand ~~acceleration~~paid for by BSP. ~~This~~ ~~nonpayment~~BSP also agreed to participate in and fund 65.0% of the ~~semi-annual~~estimated ~~interest~~well ~~payment~~costs onfor ~~the~~six ~~Second~~designated ~~Lien~~wells ~~Notes~~in isWarrior anNorth, ~~event~~Ohio, all of ~~default~~which ~~under~~have ~~the~~been ~~Company’s~~drilled, ~~Term~~completed, ~~Loan~~placed in sales and ~~under~~paid ~~the~~for ~~indentures~~by ~~governing~~BSP. BSP also has the ~~Existing~~option ~~Notes,~~to ~~which~~participate ~~upon~~in ~~requisite~~the ~~notice,~~development ~~would~~of ~~result~~36 inadditional anwells ~~acceleration~~and would fund 65.0% of the ~~maturity~~estimated ~~dates~~well ofcosts for the ~~Term~~designated ~~Loan~~wells ~~and~~in ~~Existing~~return ~~Notes~~for a 65. ~~See~~0% ~~Note~~working 1interest. To date, ~~Basis~~BSP ofhas ~~Presentation~~exercised ~~and~~its ~~Principles~~option to participate in 23 of ~~Consolidation~~these ~~and~~additional ~~Note~~wells. 18Total ~~Subsequent~~consideration ~~Events~~for this transaction could be up to $175.0 million with approximately $134.0 million committed as of June 30, 2018. BSP has paid for its interest in the elected wells as of December 31, 2017, and no additional ~~information~~elections onhave occurred during the ~~non-payment~~quarter ended June 30, 2018. The remainder of the ~~semi~~proceeds may be received if BSP makes additional elections as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-~~annual~~20% working interest ~~payment~~in ~~due~~acreage located within each of the units in which it participates. As of June 30, 2018, all 45 committed wells were in line and producing.

~~Following~~The ~~the~~BSP ~~completion~~transaction ofconstitutes ~~the~~a ~~Exchange,~~pooling ~~we entered into debt-for equity exchanges during the remainder~~ of ~~2016,~~assets ~~with~~in ~~certain~~a ~~holders~~joint ofundertaking ~~our~~to ~~Existing~~develop ~~Notes,~~these asspecific ~~well~~properties asfor ~~holders of our Second Lien Notes, in~~ which ~~such~~there ~~Existing~~is ~~Notes~~substantial ~~and~~uncertainty ~~Second~~about ~~Lien~~the ~~Notes~~ability ~~were~~to ~~exchanged~~recover ~~for~~the ~~unrestricted~~costs ~~shares~~applicable ofto our ~~common~~interest ~~stock. These exchanges resulted~~ in the ~~retirement of $27~~properties.7 ~~million~~Under inthe ~~aggregate~~terms ~~principal amount~~ of ~~our~~the ~~remaining~~agreement, ~~Existing~~we ~~Notes~~hold ~~and~~a ~~$45.7~~substantial ~~million~~obligation infor ~~aggregate~~future ~~principal amount of our outstanding Second Lien Notes~~performance, inwhich ~~exchange~~may ~~for~~not ~~the~~be ~~issuance~~proportionally ofreimbursed aby ~~total of approximately 2~~BSP.4 ~~million~~Due ~~shares~~to ~~of unrestricted common stock during~~ the ~~year~~uncertainty ~~ended~~that ~~December~~exists ~~31,~~on ~~2016. During~~ the ~~year~~recoverability ~~ended~~of ~~December 31,~~costs ~~2017 ,~~associated ~~we completed debt-for equity exchanges~~ with ~~certain holders of~~ our ~~Existing~~retained ~~Notes. These exchanges resulted in the retirement of approximately $0.9 million in aggregate principal amount of our remaining Existing Notes~~interest, inproceeds ~~exchange~~received ~~for~~from ~~approximately~~BSP ~~0.1~~are ~~million~~considered ~~shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in~~ a ~~gain for~~recovery ~~the three months ended March 31, 2017~~ of ~~approximately~~costs ~~$0.4~~and ~~million,~~no ~~presented~~gain asor ~~Gain~~loss onis ~~Extinguishments of Debt in our Consolidated Statements of Operations~~recognized.

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

On January 11, 2017, we, together with MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc. sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation. 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 us, 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 was held in escrow and released to us in December 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. 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 amounts outstanding under our prior revolving line of credit and for general corporate purposes.

Sale of Westmoreland Assets

On March 13, 2018, we entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which we agreed to sell to XPR certain of its non-operated oil and gas interests in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to us. In a related transaction, we entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which we agreed to sell to COG2 its 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018, with an effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject to customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018, prior to closing adjustments. Approximately $0.2 million of the total proceeds due to us is being held in escrow. The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.

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 permitted6. ~~The~~ ~~Indentures~~FUTURE ~~also~~ABANDONMENT ~~contain~~COST customary events of default. In certain circumstances, the individual trustees under the Indentures or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

AsFuture ofabandonment ~~March 31,~~costs ~~2018~~are ~~and~~recognized ~~December 31,~~as ~~2017,~~obligations weassociated ~~had~~with ~~recorded~~the onretirement ~~our~~of ~~Consolidated~~tangible ~~Balance~~long-lived ~~Sheets~~assets ~~approximately~~that ~~$12.8~~result ~~million~~from ~~and~~the ~~$14.0~~acquisition ~~million,~~and ~~respectively,~~development of ~~net~~the ~~premium/discounts~~asset. ~~related~~We torecognize the ~~Senior~~fair ~~Notes.~~value ~~The~~of ~~amortization~~a ofliability ~~our~~for ~~net~~a ~~premium/discounts ,~~retirement ~~which~~obligation ~~follows~~in the ~~effective~~period ~~interest~~in ~~method,~~which ~~increased~~the ~~interest~~liability ~~expense~~is ~~by approximately $1~~incurred.2 ~~million~~For ~~for~~natural ~~the~~gas ~~three~~and ~~months~~oil ~~ended March 31~~properties, ~~2018. The~~this ~~amortization~~is ofthe ~~our~~period ~~net~~in ~~premium/discounts~~which ~~decreased interest expense by approximately $3.8 million for~~ the ~~three~~natural ~~months~~gas ~~ended~~or ~~March~~oil ~~31,~~well ~~2017. Interest~~ is ~~payable~~acquired ~~semi-annually~~or ~~on our Existing Notes~~drilled. ~~Interest~~The onfuture ~~the~~abandonment ~~2020~~cost ~~Notes~~ is ~~paid~~capitalized atas apart ~~rate~~ of ~~8.875%~~the ~~per~~carrying ~~annum~~amount ~~on June 1 and December 1~~ of ~~each~~our ~~year,~~natural ~~while~~gas ~~interest~~and onoil ~~the~~properties ~~2022 Notes is paid~~ at aits ~~rate~~discounted offair 6value.~~25%~~ ~~per~~The ~~annum~~liability onis ~~February~~then 1accreted ~~and~~each ~~August~~period 1until ofthe ~~each~~liability ~~year.~~is ~~Total~~settled ~~interest~~or ~~expense for~~ the ~~three~~natural ~~months~~gas ~~ended~~or ~~March 31,~~oil ~~2018~~well is ~~composed of non-cash amortization of $4.4 million~~sold, ~~cash~~at ~~interest~~which ~~payments~~time ofthe ~~$6.8~~liability ~~million,~~is ~~capitalized interest of $(1~~reversed.2) ~~million~~If ~~and~~the anfair ~~increase~~value ~~in accrued interest~~ of ~~$12.6~~a ~~million. Total~~recorded ~~interest~~future ~~expense~~abandonment ~~for~~cost ~~the three months ended March 31~~changes, ~~2017~~a revision is ~~composed~~recorded ofto ~~non-cash~~both ~~amortization~~the ofasset ~~$6.3~~retirement ~~million,~~obligation ~~cash interest payments of $1.3 million~~ and anthe ~~increase~~asset inretirement ~~accrued interest of $1~~cost.5 ~~million.~~

			March 31, 2018
			Principal			Deferred Gain on Debt Restructurings, Net		Net Carrying Value
Term Loans, Net
	Term Loan Draw - due April 2020		$	221,000		$	—	$	221,000
Senior Notes, Net
	8.875% Senior Notes due 2020		$	7,333		$	—	$	7,333
	6.25% Senior Notes due 2022			5,363			—	$	5,363
	1% / 8% Second Lien Senior Notes due 2020			587,606			45,813	$	633,419
			$	600,302		$	45,813	$	646,115
Other Long-Term Debt
	Long-Term Capital Leases - Equipment Financing
		Due March, 2021	$	596
		Due June, 2021		1,337
		Due September, 2021		1,505
		Due May, 2022		6,616
		Total Capital Lease Obligations	$	10,054
		Less: Current Portion of Capital Leases		(2,082	)
			$	7,972

Accretion expense totaled $0.2 million and $0.5 million for the three and six months ended June 30, 2018, respectively, and $0.5 million and $1.0 million for the three and six months ended June 30, 2017, respectively. These amounts are recorded as depreciation, depletion, amortization, and accretion 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.

The weighted average interest rate on borrowed balances under the Term Loan for the three months ended March 31, 2018 was approximately 10.5%. The weighted average interest rate on the Senior Credit Facility for the three months ended March 31, 2017 was approximately 3.7%. The average interest rate on our capital leases for the three months ended March 31, 2018 and 2017 was approximately 16.8% and 11.0%, respectively. As of March 31, 2018, the Deferred Gain on Debt Restructurings, Net includes Unamortized Premiums/Discounts of $12.8 million, Unamortized Debt Issuance Costs of $30.8 million and Unamortized Deferred Gain on Debt Restructurings of $27.7 million.

($ in Thousands)	June 30, 2018
Beginning Balance at January 1, 2018	$	9,939
Future Abandonment Obligation Incurred	$	137
Future Abandonment Obligation Settled	$	(156	)
Future Abandonment Obligation Cancelled or Sold	$	(877	)
Future Abandonment Obligation Revision of Estimated Obligation	$	99
Future Abandonment Obligation Accretion Expense	$	473
Total Future Abandonment Cost¹	$	9,616

¹ Includes approximately $1.0 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

7. CONCENTRATIONS OF CREDIT RISK

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions (see Note 8, Debt, to our Consolidated Financial Statements). We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled cash settlement date. For additional information, see Note 9, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. For the six months ended June 30, 2018, approximately 98.9% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 62.1% of commodity sales. We believe the growth in our Appalachian estimated proved reserves, as well as the quantity of purchasers, will help us to minimize our future risks by diversifying our ratio of condensate and gas sales.

8. 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, 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 prior amended and restated senior secured revolving credit agreement with Royal Bank of Canada, as Administrative Agent, and the lenders from time to time party thereto (the “Prior 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 to refinance the loans then outstanding under the Prior Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility were used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes. We cash collateralized our outstanding letters of credit during the second quarter of 2018 in the amount of approximately $33.1 million. The maximum commitments of the lenders under the Term Loan were initially limited to $300,000,000. Subsequent to certain events of default under the Term Loan, we were limited to drawing approximately $261.3 million, inclusive of amounts drawn to cash collateralize the letters of credit. As of June 30, 2018, we had approximately $228.2 million in borrowings outstanding and approximately $33.1 million in outstanding cash collateralized letters of credit.

Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan were 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 one 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 “Make Whole Amount”). Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at June 30, 2018 they have been recorded at their fair value using Level 2 inputs. At March 31, 2018, we had recorded a fair value liability of approximately $53.0 million as Short-Term Derivative Instruments on our Consolidated Balance Sheet. During the second quarter of 2018, the Make Whole Amount became due and payable as a result of certain events of default and the subsequent acceleration of debt. As of June 30, 2018, the Make Whole Amount of $50 million, as referenced in the Restructuring Support Agreement, has been recorded in Accounts Payable on our Consolidated Balance Sheet. For the six months ended June 30, 2018, we have recorded a realized loss on derivatives of $50.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, that led to the Chapter 11 Bankruptcy filing. As of December 31, 2017, the fair value of these embedded derivatives was not material.

Debtor-In-Possession Term Loan

On May 23, 2018, we executed a senior-secured debtor-in-possession term loan agreement (“DIP Facility”) with AGES, as administrative agent, AGES, as collateral agent , Macquarie Bank Limited, as issuing bank and the lenders from time to time party thereto. The DIP Facility has a maturity date of November 18, 2018. In accordance with the final court order approving the DIP Facility dated July 11, 2018, the DIP Facility effectively consolidates our prior Term Loan balances of $261.3 million, the Make-Whole Amount of $50.0 million and additional borrowing capacity of $100.0 million (the “Additional Capacity”). As of June 30, 2018, we had $35.0 million in outstanding Additional Capacity borrowings under the DIP Facility which we incurred as interim financing approved by the Bankruptcy Court. Borrowings under the DIP Facility 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. Upon the occurrence and continuance of an event of default under the DIP Facility, all outstanding loans bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable in arrears on the last business day of each March, June, September and December. Interest on the Make-Whole Amount accrues from July 11, 2018 until the maturity date. Under the DIP Facility, we paid a $3.8 million up-front commitment fee which we expensed to Reorganization Items, net on our Statement of Operations. Additionally, we have agreed to pay an unused commitment fee of 3.25% on the average daily unused amount of the DIP Facility. The DIP Facility 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 DIP Facility also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after June 30, 2018, the PDP Coverage Ratio (as defined in the DIP Facility) will not be less than 1.25 to 1.00; (2) our liquidity at all times must be greater than $10.0 million, and (3) each Friday we are required to submit budget variance reports showing that (i) aggregated receipts are not less than 85% of budgeted receipts, (ii) aggregated disbursements, other than capital expenditures, are not greater than 115% of budgeted disbursements and (iii) actual capital expenditures are not greater than 105% of budgeted capital expenditures. As of June 30, 2018, our PDP Coverage Ratio was 1.85 to 1.00 and our liquidity was approximately $88.8 million. To date we have complied with all budget variance testing covenants.

Obligations under the DIP Facility are secured by a perfected first priority lien and a perfected junior lien on, and security interest in, all present and after-acquired property not subject to a valid, perfected and non-avoidable lien or security interest in existence on the Petition Date or to a valid lien in existence on the Petition Date that is perfected subsequent to the Petition Date as permitted by Bankruptcy Code Section 546(b). Obligations under the DIP Facility are also secured by a perfected first priority priming lien on, and security interest in, all prepetition collateral.

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”; the Existing Notes, together with the Second Lien Notes are collectively referred to herein as the “Senior 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 and (ii) 10.1 million shares of our common stock (the “Shares”). Subsequent to the Exchange, we had a total of $12.7 million of Existing Notes and $587.6 million of Second Lien Notes. We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the Second Lien Notes are greater than the net carrying value of the Existing Notes. As such, no gain was recognized within our GAAP basis financial statements and a new effective interest rate was established.

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 Second Lien Notes, in which such Existing Notes and Second Lien Notes were exchanged for unrestricted shares of our common stock. These exchanges resulted in the retirement of $27.7 million in aggregate principal amount of our remaining Existing Notes and $45.7 million in aggregate principal amount of our outstanding Second Lien Notes, in exchange for the issuance of a total of approximately 2.4 million shares of unrestricted common stock during the year ended December 31, 2016. During the year ended December 31, 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 in aggregate principal amount 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 for the three months ended March 31, 2017 of approximately $0.4 million, presented as Gain on Extinguishments of Debt in our Consolidated Statements of Operations.

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. The Indentures also contain customary events of default. In certain circumstances, the individual trustees under the Indentures or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The trustee under the Indenture governing the Existing Notes declared the Existing Notes immediately due and payable on May 3, 2018. Our obligations under the Indenture governing the Second Lien Notes was automatically accelerated at the time of the filing of the Bankruptcy Petitions.

Interest is payable on our Second Lien Notes at a rate of 8.0% per annum on April 1 and October 1 of each year. We have not made the semi-annual interest payment to the holders of our Second Lien Notes that was due on April 2, 2018, and did not make the interest payment prior to the expiration of the 30 day grace period. On May 18, 2018, we ceased accruing interest on the Second Lien Notes in accordance with the provisions of ASC 852. Contractual interest that we have not accrued for the Second Lien Notes for the period of May 18, 2018 through June 30, 2018 is approximately $5.6 million. As of June 30, 2018, we had approximately $29.6 million of accrued interest related to the Second Lien Notes recorded in the Accrued Interest Payable component of our Liabilities Subject to Compromise balances on our Consolidated Balance Sheet.

Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is payable at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is payable at a rate of 6.25% per annum on February 1 and August 1 of each year. On May 18, 2018, we ceased accruing interest on the Existing Notes in accordance with the provisions of ASC 852. Contractual interest that we have not accrued for the Existing Notes for the period May 18, 2018 through June 30, 2018 is approximately $0.1 million. As of June 30, 2018, we had approximately $0.4 million of accrued interest related to the Existing NotesSecond Lien Notes recorded in the Accrued Interest Payable component of our Liabilities Subject to Compromise balances on our Consolidated Balance Sheet.

As of December 31, 2017, we had recorded on our Consolidated Balance Sheet approximately $50.1 million of deferred gain on debt restructurings related to the Senior Notes. During the second quarter of 2018, in accordance with ASC 852 and in conjunction with the filing of our Bankruptcy Petition, we adjusted the carrying value of the Senior Notes to equal the outstanding principal due on the notes, plus interest that had been accrued up to May 18, 2018, (Petition Date). Adjusting the carrying value of the Senior Notes resulted in recognition of the remaining unamortized portion of the deferred gain on debt restructurings in the amount of approximately $43.6 million in Reorganization Items, Net, in our Consolidated Statement of Operations.

		June 30, 2018
		Secured Debt		Debt Balances included in Liabilities Subject to Compromise


Term Loan - due April 2020		$	261,315	$	—
Debtor-In-Possession Term Loan - due November 2018		$	35,000	$	—


8.875% Senior Notes due 2020		$	—	$	7,333
6.25% Senior Notes due 2022			—		5,363
1% / 8% Second Lien Senior Notes due 2020			—		587,606
	Total Senior Notes	$	—	$	600,302

Long-Term Capital Leases - Equipment Financing
	Due March, 2021	$	—	$	557
	Due June, 2021		—		1,254
	Due September, 2021		—		1,428
	Due May, 2022		—		6,324
	Total Capital Lease Obligations	$	—	$	9,563
	Debt Balances Subject to Compromise	$	—	$	609,865

The weighted average interest rate on borrowed balances under the DIP Facility and the Term Loan for the three and six months ended June 30, 2018 was approximately 12.0% and 11.0%, respectively. The average interest rate on our capital leases for the three and six months ended June 30, 2018 was approximately 16.5% and 16.8%, respectively.

			December 31, 2017
			Principal		Unamortized net Premium / Discount			Unamortized Debt Issuance Costs			Deferred Gain on Debt Restructurings, Net			Net Carrying Value

Term Loans, Net
	Term Loan Draw - due April 2020		$	189,500	$	(4,711	)	$	(2,761	)	$	—		$	182,028

Senior Notes, Net
	8.875% Senior Notes due 2020		$	7,333	$	—		$	—		$	(60	)	$	7,273
	6.25% Senior Notes due 2022			5,363		—			—			(67	)		5,296
	1% / 8% Second Lien Senior Notes due 2020			587,606		—			—			50,196			637,802
			$	600,302	$	—		$	—		$	50,069		$	650,371

Other Long-Term Debt
	Long-Term Capital Leases and Other Notes Payable- Equipment Financing
		Due March, 2021												$	632
		Due June, 2021													1,418
		Due September, 2021													1,578
		Due May 2022													6,454
		Total Capital Lease Obligations												$	10,082
		Less: Current Portion of Capital Leases and Other Notes Payable													(1,926	)
														$	8,156

As of December 31, 2017, the Deferred Gain on Debt Restructurings, Net includes Unamortized Premiums/Discounts of $14.0 million, Unamortized Debt Issuance Costs of $33.6 million and Unamortized Deferred Gain on Debt Restructurings of $30.4 million.

~~The following is the principal maturity schedule for debt outstanding as of March 31, 2018:~~20

2018(a)	$	822,833
2019		2,341
2020		2,739
2021		2,582
2022		861
Thereafter		—
Total (b)	$	831,356

9. 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) ~~Due~~portion of the exposure to ~~existing~~adverse market changes, we enter into natural gas, NGL and ~~anticipated~~oil ~~covenant~~commodity ~~violations~~derivative instruments to establish price floor protection. As such, ~~the~~when ~~Company’s~~commodity ~~Term~~prices ~~Loan~~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, 2018 and ~~Senior~~December 31, ~~Notes~~2017, ~~were~~our ~~classified~~commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, basis swaps and three-way collars. We did not designate these instruments as ~~current~~cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as ~~December~~Gain 31(Loss) on Derivatives, ~~2017~~Net in the Consolidated Statement of Operations.

(b) Excludes $45.8 million of Deferred Gain on Debt Restructurings, Net.

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 March 31, 2018 and December 31, 2017, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, 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 in the Consolidated Statement of Operations.

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 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 $24.09 million and $36.49 million in relation to our commodity derivatives during the three and six months ended ~~March~~June 3130, 2018, respectively and 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.

Embedded Derivatives – Yield Maintenance and Call Protection

We entered into the Term Loan in April 2017, which included certain call protection and yield maintenance provisions that require accelerated payments upon certain events. Prepayments (including mandatory prepayments), terminations, certain events of default, 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 one 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.

Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at March 31, 2018 they have been recorded at their fair value using Level 2 inputs. ~~For~~As ~~the~~of ~~three~~June ~~months ended March 31~~30, 2018, we have recorded a fair value liability of approximately $5350.0 million as ~~Short-Term~~Current ~~Derivative~~Liability ~~Instruments~~ on our Consolidated Balance Sheet. For the ~~three~~six months ended ~~March~~June 3130, 2018, we recorded a loss of approximately $5350.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which ~~have~~ led to ~~the~~our ~~Company~~decision ~~deciding~~ to file ~~Chapter~~the 11 Bankruptcy ~~which have caused these amounts to become due and payable~~Petitions. ~~As of December 31, 2017, the fair value of these embedded derivatives was not material.~~ As of December 31, 2017, the fair value of these embedded derivatives was not material.

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. 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 ~~March~~June 3130, 2018 and December 31, 2017, the contingent consideration contract was valued at $2.15 million and $1.7 million, respectively. For the three month period ended ~~March~~June 3130, 2018, the average index price for oil as specified in the contract was in excess of the required threshold price for the quarter, and we recognized income of approximately $0.8 million, representing the discounted fair value of the additional consideration earned during the quarter. The contract stipulates that the buyer will remit to us $0.9 million not later than ~~April~~July 15, 2019, for the consideration earned during the three months ended ~~March~~June 3130, 2018. The discounted fair value of approximately $0.8 million is included in Accounts Receivable on our Consolidated Balance Sheets as of ~~March~~June 3130, 2018.

Derivative Instruments

~~The~~On ~~following~~May ~~table~~18, ~~summarizes~~2018, the ~~location~~Bankruptcy ~~and~~Court ~~amounts~~approved a motion to continue our derivative programs in the normal course of ~~gains~~business. ~~and~~In ~~losses~~conjunction onwith the Bankruptcy Petitions, one of our derivative ~~instruments~~counterparties elected to terminate their outstanding contracts with us, ~~none~~resulting in a $2.0 million liability. Approximately $0.8 million was related to the fair value of the derivatives on the date of termination, which ~~are~~was ~~designated~~recognized as ~~hedges~~(Loss) Gain on Derivatives, Net for ~~accounting~~the ~~purposes~~three and six months ended June 30, in2018. ~~our~~Approximately ~~accompanying~~$1.2 ~~Consolidated~~million ~~Statements~~was related to costs associated with the early termination of ~~Operations~~the derivative positions and was recorded as Reorganization Items, Net for the three and six months ended ~~March 31~~June 30, 2018: .

	For the Three Months Ended March 31,
($ in Thousands)	2018			2017
Oil	$	(1,735	)	$	1,137
Natural Gas		3,392			(59	)
NGLs		3,669			8,720
Contingent Consideration		1,214			(1,417	)
Embedded Derivatives		(52,965	)		—
(Loss) Gain on Derivatives, Net	$	(46,426	)	$	8,381

The following table summarizes the location and amounts of gains and losses on our derivative instruments, 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, 2018 and 2017:

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 $64.6 million and approximately $19.4 million at March 31, 2018 and December 31, 2017, respectively.

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
($ in Thousands)	2018			2017			2018			2017
Oil	$	(3,817	)	$	791		$	(5,553	)	$	1,934
Natural Gas		(213	)		6,132			3,179			6,072
NGLs		(14,383	)		3,938			(10,714	)		12,653
Contingent Consideration		1,120			(475	)		2,334			(1,893	)
Embedded Derivatives		2,965			—			(50,000	)		—
(Loss) Gain on Derivatives, Net	$	(14,328	)	$	10,386		$	(60,754	)	$	18,766

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 $24.9 million and approximately $19.4 million at June 30, 2018 and December 31, 2017, respectively.

~~Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2018 consisted of:~~ 22

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		139,250	Bbls	$	—	$	—	$	—	$	57.55		$	(811	)
2018 - Collars		9,000	Bbls		—		53.00		60.00		—			(47	)
2018 - Three-Way Collars		57,000	Bbls		42.11		51.32		61.14		—			(222	)
2019 - Swaps		53,500	Bbls		—		—		—		49.04			(425	)
2019 - Collars		60,250	Bbls		—		45.00		55.07		—			(161	)
2019 - Three-Way Collars		51,000	Bbls		38.82		48.82		58.31		—			(201	)
2020 - Swaps		24,000	Bbls		—		—		—		50.63			(146	)
2020 - Collars		71,750	Bbls				45.00		55.10					(215	)
2020 - Three-Way Collars		33,725	Bbls		39.39		49.39		57.04		—			(116	)
2021 - Swaps		15,000	Bbls		—		—		—		50.40			(36	)
2021 - Collars		63,750	Bbls		—		45.00		55.02		—			(197	)
2021 - Three-Way Collars		13,250	Bbls		39.10		49.10		60.41		—			(45	)
2022 - Swaps		6,750	Bbls		—		—		—		50.00			—
2022 - Collars		36,000	Bbls		—		45.00		54.75		—			(107	)
2022 - Three-Way Collars		5,500	Bbls		40.00		50.00		60.50		—			(11	)
		639,725	Bbls										$	(2,740	)
Natural Gas
2018 - Swaps		18,342,500	Mcf		—		—		—		2.98		$	2,400
2018 - Three-Way Collars		7,600,000	Mcf		2.33		2.89		3.49		—			1,124
2018 - Calls		4,370,000	Mcf		—		—		3.97		—			(38	)
2018 - Collars		3,965,000	Mcf		—		2.60		3.04		—			(153	)
2018 - Basis Swaps - Dominion South		10,625,000	Mcf		—		—		—		(0.82	)		(2,056	)
2018 - Basis Swaps - Texas Gas		11,000,000	Mcf		—		—		—		(0.13	)		448
2019 - Swaps		11,620,000	Mcf		—		—		—		2.84			255
2019 - Three-Way Collars		11,250,000	Mcf		2.29		2.76		3.34		—			282
2019 - Collars		9,051,750	Mcf		—		2.56		3.04		—			(270	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(2,721	)
2020 - Swaps		5,542,500	Mcf		—		—		—		2.88			135
2020 - Three-Way Collars		7,680,000	Mcf		2.27		2.73		3.24		—			279
2020 - Collars		6,760,000	Mcf		—		2.56		3.04		—			(153	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(1,519	)
2021 - Swaps		3,875,000	Mcf		—		—		—		2.77			(5	)
2021 - Three-Way Collars		4,083,750	Mcf		2.21		2.68		3.13		—			66
2021 - Collars		3,530,000	Mcf		—		2.53		3.05		—			(77	)
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2022 - Swaps		2,730,000	Mcf		—		—		—		2.73			(42	)
2022 - Three-Way Collars		2,047,500	Mcf		2.15		2.65		3.10		—			21
2022 - Collars		2,195,000	Mcf		—		2.51		3.05		—			(52	)
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
		160,963,000	Mcf										$	(3,168	)
NGLs
2018 - C3+ NGL Swaps		1,137,405	Bbls		—		—		—		34.05		$	(5,540	)
2018 - Ethane Swaps		1,302,000	Bbls		—		—		—		12.22			750
2019 - C3+ NGL Swaps		957,943	Bbls		—		—		—		29.98			(1,883	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(495	)
2019 - Ethane Swaps		1,317,750	Bbls		—		—		—		12.61			805
2019 - C5 Three-Way Collars		7,536	Bbls		—		32.31		50.00		55.75			(24	)
2020 - C3+ NGL Swaps		347,689	Bbls		—		—		—		30.40			(996	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(124	)
2020 - Ethane Swaps		1,150,750	Bbls		—		—		—		12.37			113
2020 - C5 Three-Way Collars		41,225	Bbls		—		34.87		49.94		57.36			(82	)
2021 - C3+ NGL Swap		210,206	Bbls		—		—		—		31.62			(402	)
2021 - Ethane Swaps		805,000	Bbls		—		—		—		12.32			93
2021 - C5 Three-Way Collars		63,398	Bbls		—		38.99		48.99		60.40			(37	)
2022 - C3+ NGL Swap		62,966	Bbls		—		—		—		32.60			(114	)
2022 - Ethane Swaps		379,250	Bbls		—		—		—		12.31			52
2022 - C5 Three-Way Collars		22,460	Bbls		—		39.11		49.11		60.41			(9	)
		7,946,878	Bbls										$	(7,893	)

Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2018 consisted of:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		85,750	Bbls	$	—	$	—	$	—	$	57.47		$	(817	)
2018 - Three-Way Collars		42,000	Bbls		41.82		51.09		60.75		—			(413	)
2019 - Swaps		118,000	Bbls		—		—		—		55.89			(1,231	)
2019 - Collars		18,000	Bbls		—		45.00		55.80		—			(125	)
2019 - Three-Way Collars		42,000	Bbls		38.57		48.57		58.86		—			(375	)
2020 - Swaps		24,000	Bbls		—		—		—		51.00			(304	)
2020 - Collars		22,500	Bbls				45.00		55.80					(167	)
2020 - Three-Way Collars		21,500	Bbls		38.95		48.95		60.22		—			(103	)
2021 - Swaps		6,000	Bbls		—		—		—		51.00			(76	)
2021 - Collars		16,500	Bbls		—		45.00		55.80		—			(125	)
2021 - Three-Way Collars		62,500	Bbls		37.44		47.04		57.98		—			(240	)
2022 - Three-Way Collars		23,000	Bbls		39.35		49.35		60.43		—			(60	)
		481,750	Bbls										$	(4,037	)
Natural Gas
2018 - Swaps		12,127,500	Mcf		—		—		—		2.98		$	394
2018 - Three-Way Collars		4,260,000	Mcf		2.31		2.88		3.55		—			310
2018 - Calls		2,920,000	Mcf		—		—		3.97		—			(19	)
2018 - Collars		2,222,500	Mcf		—		2.60		3.04		—			(134	)
2018 - Basis Swaps - Dominion South		9,808,000	Mcf		—		—		—		(0.83	)		(1,858	)
2018 - Basis Swaps - Texas Gas		7,360,000	Mcf		—		—		—		(0.13	)		324
2019 - Swaps		7,500,000	Mcf		—		—		—		2.91			129
2019 - Three-Way Collars		8,045,000	Mcf		2.35		2.81		3.43		—			313
2019 - Collars		4,471,750	Mcf		—		2.62		3.03		—			(227	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(3,725	)
2020 - Swaps		4,642,500	Mcf		—		—		—		2.90			242
2020 - Three-Way Collars		4,935,000	Mcf		2.33		2.77		3.31		—			350
2020 - Collars		2,645,000	Mcf		—		2.65		3.03		—			(34	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(2,068	)
2021 - Swaps		900,000	Mcf		—		—		—		2.90			59
2021 - Three-Way Collars		1,346,250	Mcf		2.32		2.74		3.20		—			97
2021 - Collars		792,500	Mcf		—		2.65		3.05		—			43
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2022 - Collars		147,500	Mcf		—		2.65		3.05		—			11
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
		108,818,500	Mcf										$	(6,533	)
NGLs
2018 - C3+ NGL Swaps		640,036	Bbls		—		—		—		33.06		$	(8,150	)
2018 - Ethane Swaps		780,000	Bbls		—		—		—		12.13			(450	)
2019 - C3+ NGL Swaps		570,814	Bbls		—		—		—		30.90			(4,524	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(964	)
2019 - Ethane Swaps		1,264,750	Bbls		—		—		—		12.60			322
2020 - C3+ NGL Swaps		191,112	Bbls		—		—		—		32.22			(1,875	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(241	)
2020 - Ethane Swaps		1,007,750	Bbls		—		—		—		12.31			(73	)
2021 - C3+ NGL Swap		88,404	Bbls		—		—		—		41.70			(599	)
2021 - Ethane Swaps		724,000	Bbls		—		—		—		12.27			(98	)
2022 - C3+ NGL Swap		9,420	Bbls		—		—		—		50.50			(33	)
2022 - Ethane Swaps		352,250	Bbls		—		—		—		12.27			(107	)
		5,769,836	Bbls										$	(16,791	)

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 is summarized below: 23

	March 31,			December 31,
($ in Thousands)	2018			2017
Short-Term Derivative Assets:
NGL—Swaps	$	1,549		$	928
Natural Gas—Swaps		2,672			3,734
Natural Gas—Collars		—			183
Natural Gas—Basis Swaps		448			191
Natural Gas—Three-Way Collars		1,222			1,721
Contingent Consideration - Sale of Illinois Basin		1,841			1,251
Total Short-Term Derivative Assets	$	7,732		$	8,008
Long-Term Derivative Assets:
NGL—Swaps	$	1,511		$	409
Natural Gas—Swaps		404			411
Natural Gas—Basis Swaps		—			—
Natural Gas—Three-Way Collars		675			429
Contingent Consideration - Sale of Illinois Basin		290			470
Total Long-Term Derivative Assets	$	2,880		$	1,719
Total Derivative Assets	$	10,612		$	9,727
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(46	)	$	(31	)
Crude Oil—Three-Way Collars		(289	)		(92	)
Crude Oil—Swaps		(914	)		(518	)
NGL—Swaps		(7,205	)		(10,281	)
NGL—Collars		(124	)		—
Natural Gas—Three-Way Collars		(25	)		(49	)
Natural Gas—Collars		(206	)		(146	)
Natural Gas—Basis Swaps		(2,738	)		(3,621	)
Natural Gas—Call		(38	)		(154	)
Natural Gas—Swaps		(121	)		—
Embedded Derivatives		(52,965	)		—
Total Short - Term Derivative Liabilities	$	(64,671	)	$	(14,892	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	(306	)	$	(161	)
Crude Oil—Swaps		(504	)		(202	)
Crude Oil—Collars		(681	)		(425	)
NGL—Swaps		(2,977	)		(4,482	)
NGL—Collars		(495	)		(385	)
NGL—Three Way Collars		(152	)		(66	)
Natural Gas—Swaps		(212	)		(423	)
Natural Gas—Swaption		—			—
Natural Gas—Basis Swaps		(4,650	)		(7,120	)
Natural Gas—Collars		(499	)		(713	)
Natural Gas—Call		—			—
Natural Gas—Three-Way Collars		(100	)		(272	)
Total Long-Term Derivative Liabilities	$	(10,576	)	$	(14,249	)
Total Derivative Liabilities	$	(75,247	)	$	(29,141	)

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, 2018 and December 31, 2017 is summarized below:

	June 30,			December 31,
($ in Thousands)	2018			2017
Short-Term Derivative Assets:
NGL—Swaps	$	365		$	928
Natural Gas—Swaps		1,118			3,734
Natural Gas—Collars		22			183
Natural Gas—Basis Swaps		328			191
Natural Gas—Three-Way Collars		513			1,721
Contingent Consideration - Sale of Illinois Basin		2,450			1,251
Total Short-Term Derivative Assets	$	4,796		$	8,008
Long-Term Derivative Assets:
NGL—Swaps	$	308		$	409
Natural Gas—Swaps		422			411
Natural Gas—Collars		119			—
Natural Gas—Three-Way Collars		614			429
Contingent Consideration - Sale of Illinois Basin		—			470
Total Long-Term Derivative Assets	$	1,463		$	1,719
Total Derivative Assets	$	6,259		$	9,727
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(42	)	$	(31	)
Crude Oil—Three-Way Collars		(650	)		(92	)
Crude Oil—Swaps		(1,442	)		(518	)
NGL—Swaps		(11,700	)		(10,281	)
NGL—Collars		(482	)		—
Natural Gas—Three-Way Collars		(56	)		(49	)
Natural Gas—Collars		(268	)		(146	)
Natural Gas—Basis Swaps		(3,725	)		(3,621	)
Natural Gas—Call		(19	)		(154	)
Natural Gas—Swaps		(711	)		—
Total Short - Term Derivative Liabilities	$	(19,095	)	$	(14,892	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	(541	)	$	(161	)
Crude Oil—Swaps		(986	)		(202	)
Crude Oil—Collars		(376	)		(425	)
NGL—Swaps		(4,560	)		(4,482	)
NGL—Collars		(723	)		(385	)
NGL—Three Way Collars		—			(66	)
Natural Gas—Swaps		(5	)		(423	)
Natural Gas—Basis Swaps		(4,671	)		(7,120	)
Natural Gas—Collars		(213	)		(713	)
Natural Gas—Three-Way Collars		—			(272	)
Total Long-Term Derivative Liabilities	$	(12,075	)	$	(14,249	)
Total Derivative Liabilities	$	(31,170	)	$	(29,141	)

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Our Level 2 fair value measurements are composed 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, probability factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of ~~March~~June 3130, 2018 and December 31, 2017 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 ~~March~~June 3130, 2018 or December 31, 2017.

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 ~~March~~June 3130, 2018 and for the year ended December 31, 2017 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 March 31, 2018
				Fair Value Measurements at June 30, 2018
($ in Thousands)	Total Carrying Value as of ~~March~~June 3130, 2018			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(1124,~~670~~911	)	$	—	$	(1124,~~670~~911	)	$	—
Embedded Derivatives	$	(52,965	)	$	—	$	(52,965	)	$	—
				Fair Value Measurements at December 31, 2017
($ in Thousands)	Total Carrying Value as of December 31, 2017			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(19,414	)	$	—	$	(19,414	)	$	—

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 composed 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 ~~March~~June 3130, 2018 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 composed 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 ~~March~~June 3130, 2018 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 composed 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, 2018 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.

contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of March 31, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

Future Abandonment Cost

We report the fair value of 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:

	March 31, 2018				December 31, 2017
	June 30, 2018				December 31, 2017
($ in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Notes, Net of Issuance Costs	$	~~646~~600,~~115~~302	$	~~214~~6,~~080~~730	$	650,371	$	264,438
Term Loan		~~221~~261,~~000~~315		~~208~~252,~~790~~966		182,028		182,028
Capital Leases and Other Obligations		10,054		7,271		10,082		7,138
Debtor In Possession Secured Term Loan		35,000		35,000		—		—
Total	$	877,169	$	430,141	$	842,481	$	453,604
Capital Leases and Other Obligations		9,563		7,065		10,082		7,138
Total	$	906,180	$	301,761	$	842,481	$	453,604

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 ~~three~~six months ended ~~March~~June 3130, 2018 and 2017, we recorded other than temporary impairments of $812.25 million and $14.56 million, respectively, related to proven and unproved properties. We primarily use proved reserve reports in our determination of impairment of proved properties. These proved reserve reports are generated with inputs that are primarily established internally with the use of internally developed engineering estimates and methodologies. 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. Impairment considerations for unproved properties include future development plans for the leases, remaining months on the lease’s primary term, and market value for similar acreage in the area. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

910. 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.

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 March 31,
	Three Months Ended June 30,						Six Months Ended June 30,
($ in Thousands)	2018			2017			2018			2017
Income Tax Benefit (Expense)	$	—		$	—		$	—		$	—
Effective Tax Rate		0.0	%		0.0	%		0.0	%		0.0	%

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 income tax provision is composed of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items.

For the three months ended March 31, 2018, the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 21.0% primarily due to the effect of maintaining a full valuation allowance against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period. 26

For the ~~three~~six months ended ~~March~~June 3130, ~~2017~~2018, the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 3521.0% primarily due to the effect of maintaining a full valuation ~~allowances~~allowance against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period.

NoFor ~~income~~the ~~tax~~six ~~payments~~months ~~were~~ended ~~made~~June 30, ~~for~~2017 the ~~three~~estimated ~~months~~annual ~~ended~~effective ~~March 31,~~tax ~~2018~~rate ~~and~~applied ~~2017~~to ordinary losses from operations was 0. ~~Tax~~0%. The ~~refunds~~estimated ~~received~~annual ~~during~~effective ~~the~~tax ~~three~~rate ~~months~~differs ~~ended~~from ~~March 31,~~the ~~2018~~U.S. ~~were~~statutory ~~approximately~~rate $2of 35.0% ~~million,~~primarily due to the effect of maintaining a full valuation allowances against our deferred tax assets. Discrete period tax expense was not material and ~~refunds~~is ~~received~~also ~~during~~offset ~~the~~by ~~three~~a ~~months~~full ~~ended~~valuation ~~March 31,~~allowance ~~2017~~resulting ~~were~~in ~~negligible~~zero tax expense for the period.

No income tax payments were made for the six months ended June 30, 2018. Income tax payments made during the six months ended June 30, 2017 were $2.0 million. Tax refunds received during the six months ended June 30, 2018 were approximately $2.0 million, and refunds received during the six months ended June 30, 2017 were approximately $0.2 million.

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted. The Tax Act significantly changed the Internal Revenue Code, reducing the Federal statutory corporate income tax rate from 35% to 21%, allowing for bonus depreciation on certain qualified property, eliminating the alternative minimum tax for corporate taxpayers, adding new limitations on the deductibility of business interest expense deduction for net operating losses. The Tax Act also authorizes the Treasury Department to issue regulations with respect to the new provisions. We are still in the process of fully analyzing the Tax Cuts and Jobs Act and its effects on the Company. We cannot predict how the changes in the Tax Cuts and Jobs Act, regulations, or other guidance issued under it or conforming or non-conforming state tax rules might affect us or our business. In addition, there can be no assurance that U.S. tax laws, including the corporate income tax rate, will not undergo significant changes in the near future.

1011. ~~CAPITAL~~STOCKHOLDERS’ ~~STOCK~~ EQUITY

Nasdaq Delisting

On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department (the “Staff”) of The Nasdaq Stock Market LLC (“Nasdaq”) indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we request an appeal before the Nasdaq Hearings Panel (the “Panel”). We did not appeal this determination. Nasdaq filed a Form 25-NSE on April 19, 2018. Following the delisting of our common stock from Nasdaq, our common stock has been quoted on the OTC Markets Group’s Pink marketplace.

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 5, 2017, our 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 ~~March~~June 3130, 2018, we have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of ~~March~~June 3130, 2018 and December 31, 2017, shares of common stock issued and outstanding totaled 10,~~708~~707,~~287~~788 and 10,244,394, respectively. During the ~~three~~six months ended ~~March~~June 3130, 2017, we issued approximately 0.31 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes. See Note 78, ~~Long-Term~~ Debt, to our Consolidated Financial Statements for additional information regarding our debt and equity exchanges.

Preferred Stock

As of both ~~March~~June 3130, 2018 and December 31, 2017, 3,987 shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), were issued and outstanding.

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. Dividends of $1.8 million were declared by our Board of Directors in 2017, bringing dividends in arrears current through August 15, 2016. Dividends declared and paid in 2017 were composed of cash dividends of $150.00 per share in the aggregate amount of $1.2 million, for the periods of November 15, 2016 to February 15, 2016 and February 15, 2016 to May 15, 2016 and we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of May 15, 2016 to August 15, 2016, which was paid in shares of the Company’s common stock. As of March 31, 2018, we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of August 15, 2016 to November 15, 2016, which was paid in shares of the Company’s common stock. As of March 31, 2018, 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. 27

IfWe ~~dividends~~pay ~~are~~cumulative individends, ~~arrears~~when and ~~unpaid~~if ~~for~~declared, ~~six~~in cash, stock or ~~more~~a combination thereof, on a quarterly ~~periods~~basis ~~(whether~~at a rate of $600 per share, or 6.0%, per year. Dividends that are not ~~consecutive),~~declared and paid in accordance with the ~~holders~~quarterly ofschedule will accumulate from the ~~shares~~most ofrecent ~~Series~~date Aupon ~~Preferred~~which ~~Stock~~dividends were paid but will ~~have~~not ~~the~~bear ~~right~~interest. toIn ~~elect~~February ~~two~~2016, ~~additional~~we ~~directors~~suspended toour ~~serve~~quarterly ondividend payment. Dividends of $1.8 million were declared by our ~~board~~Board of ~~directors~~Directors in 2017, bringing dividends in arrears current through August 15, 2016. WeDividends dodeclared ~~not~~and ~~intend~~paid toin ~~make~~2017 were composed of cash dividends of $150.00 per share in the aggregate amount of $1.2 million, for the periods of November 15, 2016 to February 15, 2016 and February 15, 2016 to May 15, 2016 and we paid a dividend ~~payment~~of ~~due~~$150.00 onper share in the aggregate amount of $0.6 million for the period of May 15, 2016 to August 15, 2016, which was paid in shares of our common stock. On February 15, 2018 , we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of August 15, 2016 to November 15, 2016, which ~~will~~was paid in shares of our common stock; as of June 30, 2018, no additional dividends have been paid on the Series A Preferred Stock in 2018. As of June 30, 2018, accumulated dividends in arrears totaled $3.6 million. While the accumulation does not result in the presentation of a ~~total~~liability on the Consolidated Balance Sheets, the accumulation of ~~six~~unpaid ~~quarterly~~dividends ~~dividend~~during ~~payments~~the current reporting period is included in ~~arrears~~our Net Income (Loss) in the determination of Net Income (Loss) Attributable to Common Shareholders and related earnings per share calculations.

11If 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. We ~~EMPLOYEE~~did ~~BENEFIT~~not ~~AND~~make ~~EQUITY~~the ~~PLANS~~dividend payment due on May 15, 2018, which resulted in a total of six quarterly dividend payments in arrears.

12. EMPLOYEE BENEFIT AND EQUITY PLANS

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals 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 ~~three~~six months ended ~~March~~June 3130, 2018 and 2017, no new options to purchase shares of our common stock were granted. Stock-based compensation expense from operations relating to stock options outstanding for the three and six months ended ~~March~~June 3130, 2018 was negligible. Stock-based compensation expense from operations relating to stock options outstanding for the three and six months ended June 30, 2017 was ~~negligible~~$0.1 million and $0.12 million, respectively. 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 ~~three~~six months ended ~~March~~June 3130, 2018. There was no tax benefit related to stock option exercises for each of the ~~three~~six-month periods ended ~~March~~June 3130, 2018 and 2017.

A summary of the status of our issued and outstanding stock options as of ~~March~~June 3130, 2018 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding at ~~March~~June 3130, 2018		Weighted-Average Exercise Price		Number Exercisable at ~~March~~June 3130, 2018		Weighted-Average Exercise Price
	9.70		2,~~750~~667	$	9.70		~~919~~1,835	$	9.70
	16.90		6057,~~327~~169	$	16.90		4138,~~276~~118	$	16.90
	49.00		4,000	$	49.00		4,000	$	49.00
	50.40		3,070	$	50.40		3,070	$	50.40
	104.20		2,217	$	104.20		2,217	$	104.20
	223.40		3,000	$	223.40		3,000	$	223.40
			69,123	$	22.77		49,240	$	25.26
			75,364	$	30.49		54,482	$	35.95

The weighted average remaining contractual term for options outstanding at ~~March~~June 3130, 2018 was 4.54 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at ~~March~~June 3130, 2018 was 4.3 years and there was no aggregate intrinsic value. As of June 30, 2018, unrecognized compensation expense related to stock options was negligible.

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and there was no aggregate intrinsic value. As of March 31, 2018, unrecognized compensation expense related to stock options was negligible.

Restricted Stock Awards

During the ~~three~~six-month ~~months~~period ended ~~March~~June 3130, 2018, there were no issuances of restricted common stock to employees. During the ~~three~~six-month ~~months~~period ended ~~March~~June 3130, 2017, the Compensation Committee approved the issuance of an aggregate of 101,237 shares of restricted stock to 28 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.

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:

	Three Months Ended March 31, 2018	Year Ended December 31, 2017
	Six Months Ended June 30, 2018	Year Ended December 31, 2017
Expected Dividend Yield	0.0%	0%	~~0.0~~	%
Risk-Free Interest Rate	1.0%	1.0%	~~1.0~~	%
Expected Volatility – Rex Energy	58.6%	58.6%	~~58.6~~	%
Expected Volatility – Peer Group	29.8%-85.0%	29.8%-85.0%
Market Index	35.6%	35.6%	~~35.6~~	%
Expected Life	Three Years	Three Years

Compensation expense from restricted stock awards associated with our operations was $10.1 million and $01.92 million for the three and six months ended ~~March~~June 3130, 2018, respectively and it was $0.4 million and $0.4 million for the three and six months ended June 30, 2017, respectively. During the three months ended March 31, 2018, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2018. This waiver resulted in the vesting of approximately 29,411 restricted stock awards with associated expense of approximately $0.9 million. During the ~~first~~six ~~quarter~~months ofended June 30, 2017, 179,519 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~~. As of ~~March~~June 3130, 2018, total unrecognized compensation cost related to restricted common stock grants was approximately $0.43 million, which will be recognized over a weighted average period of 1.32 years.

A summary of the restricted stock activity for the ~~three~~six months ended ~~March~~June 3130, 2018 is as follows:

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2017		200,475		$	13.62
Awards		—			—
Forfeitures		(27,~~318~~817	)		15.2413
Vested		(56,~~335~~976	)		24.6572
Restricted stock awards, as of March 31, 2018	$	116,822		$	7.92
Restricted stock awards, as of June 30, 2018	$	115,682		$	7.79

~~12.~~Retention ~~COMMITMENTS~~and ~~AND~~Incentive ~~CONTINGENCIES~~Plans for Key Employees and Executives

Subsequent to the Petition Date, the Bankruptcy Court approved motions to implement a Key Employee Retention Plan (“KERP”) and a Key Executive Incentive Plan (“KEIP”). The KERP is designed as a retention tool for key employees that will pay a fixed amount of $132,500 per quarter, for a total of three quarters, beginning on or about June 30, 2018. Amounts related to the KERP are accounted for as Accrued Expenses on our Consolidated Balance Sheet and expensed as Reorganization Items, net on our Consolidated Statement of Operations. As of June 30, 2018, we had approximately $0.1 million accrued related to the KERP.

The KEIP is designed to incentivize our key executives to maximize value for the benefit of all of our stakeholders through the measurement period of May 2018 through December 2018. A portion of the payout of the KEIP is dependent on the achievement of certain performance goals, including production, lease operating expenses, and safety goals. A separate portion of the payout of the KEIP is dependent on the achievement of certain milestones for the emergence from bankruptcy through a successful plan of reorganization or closing of a sale of substantially all of the assets within certain specified timeframes. The total amount of compensation available under the KEIP plan is dependent on the level of operating performance and successful emergence from bankruptcy and range from approximately $1.2 million up to a maximum of $3.5 million in total. Amounts under the KEIP are accounted for as Accrued Expenses on our Consolidated Balance Sheet and expensed as General and Administrative Expense on our Consolidated Statement of Operations. As of June 30, 2018, we had approximately $0.4 million accrued related to the KEIP.

Additional information on the KEIP and the KERP is available from Prime Clerk, Claims and Noticing Agent for the bankruptcy proceedings, at https://cases.primeclerk.com/rexenergy/Home-Index.

13. COMMITMENTS AND CONTINGENCIES

Legal Reserves

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

The accrual of reserves for legal matters is included in Accrued 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.

26For the quarter ended June 30, 2018, there were no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, as supplemented by our Periodic Report on Form 10-Q for the period ended June 30, 2018.

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 March 31, 2018, there were no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, as supplemented by our Periodic Report on Form 10-Q for the period ended March 31, 2018.

Environmental

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

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of ~~March~~June 3130, 2018, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

As of ~~March~~June 3130, 2018, we have posted $32.0 million in various letters of credit to secure our drilling and related operations. During the second quarter, our various letters of credit were cash collateralized and the cash is shown on our Consolidated Balance Sheet as Restricted Cash.

Lease Commitments

As of ~~March~~June 3130, 2018, 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 ~~March~~June 3130, 2018 ~~and 2017~~ was approximately $0.32 million and $0.5 million, respectively, and $0.2 million and $0.5 million for the three and six months ended June 30, 2017, respectively. Lease commitments by year for each of the next five years are presented in the table below:

($ in Thousands)
2018	$	~~740~~488
2019		~~899~~903
2020		~~796~~802
2021		~~475~~484
2022		~~485~~496
Thereafter		—
Total	$	3,~~395~~173

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 $128.8 million in 2018, $1617.96 million in 2019, $17.06 million in 2020, $1617.95 million in 2021, $17.06 million in 2022 and $6668.58 million thereafter, assuming our average net revenue interest in the region of approximately 5456%. Charges incurred for unutilized processing capacity with MarkWest during the three and six months ended ~~March~~June 3130, 2018 ~~and 2017~~ were $0.6 million and $1.62 million, respectively and $1.7 million and $3.3 million during the three and six months ended June 30, 2017, respectively.

Water Supply Commitments

We have contracted with a water district in Ohio to supply bulk water in support of our Ohio drilling operations. The contract is effective from July 5, 2017 through July 4, 2022. Over the duration the contract, we are obligated to purchase 150 million gallons of water at a fixed price of $7.50 per 1,000 gallons. As of ~~March~~June 3130, 2018, our future commitment for unpurchased volumes is approximately $0.6 million.

Operational Commitments

We have contracted drilling rig services for one rig to support our Appalachian Basin operations. ~~The~~During ~~minimum cost to retain~~ the ~~rig~~second ~~would~~quarter ~~require gross payments~~ of ~~approximately~~2018, ~~$1.2~~we ~~million~~terminated ~~for~~ the ~~remainder~~contract offor ~~2018,~~this ~~which~~rig ~~would~~earlier bethan ~~partially~~its ~~offset~~original byterm. To ~~other~~satisfy ~~working~~the ~~interest~~early ~~owners~~release, ~~whose~~we ~~interest~~incurred ~~and~~approximately ~~share of these expenses vary from well to well~~$1. ~~Our~~2 ~~current~~million ~~development program ended~~ in early ~~April~~termination ~~and~~fees, wewhich ~~expect~~were toclassified ~~pay~~as ~~the~~Other ~~associated~~Operating ~~early~~expense ~~termination~~in ~~fees~~our byConsolidated ~~the~~Statement ~~end~~ of ~~the~~Operations ~~third~~as ~~quarter~~ of June 30, 2018. We also have contracted completion services in the Appalachian Basin. ~~The~~During ~~minimum~~the ~~gross~~second ~~cost~~quarter toof ~~retain~~2018, ~~these~~we ~~completion~~did ~~services~~not ismeet ~~approximately~~the ~~$2.8~~contracted ~~million~~total ~~for~~stage commitment before the ~~remainder~~end of ~~2018,~~the ~~which~~contract. To ~~would~~satisfy bethe ~~partially~~remaining ~~offset~~commitment byowed, ~~other~~we ~~working~~incurred ~~interest~~approximately ~~owners~~$0.1 million in termination fees, ~~whose~~which ~~interests~~were ~~and~~classified ~~share~~as ofOther ~~these~~Operating ~~expenses~~Expense ~~vary~~in ~~from~~our ~~well~~Consolidated toStatement ~~well~~of Operations as of June 30, 2018.

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 $~~370~~363.1 million through 2029.

For the three and six months ended ~~March~~June 3130, 2018 ~~and 2017~~, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $3134.1 million and $65.2 million, respectively and $26.34 million and $52.7 million for the three and six months ended June 30, 2017, 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 ~~March~~June 3130, 2018 ~~and 2017~~, we incurred fees related to unutilized capacity commitments of approximately $0.7 million and $1.4 million, respectively and $0.7 million and $1.4 million during the three and six months ended June 30, 2017, respectively. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

($ in Thousands)
2018	$	3725,~~992~~597
2019		5051,~~875~~096
2020		49,~~522~~724
2021		46,~~551~~729
2022		46,~~090~~260
Thereafter		~~461~~390,~~109~~656
Total	$	~~692~~610,~~139~~062

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Illinois Basin Oil Contingency

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”). An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up to $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of ~~West Texas Intermediate (“~~WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of ~~March~~June 3130, 2018, the first ~~six~~seven of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI of five out of the ~~six~~seven below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds for the first five measurement periods. As of ~~March~~June 3130, 2018 the calculated average spot price of WTI was above the threshold price in the agreement, we then have qualified to receive the additional proceeds for the current period. As of ~~March~~June 3130, 2018, we have the potential to receive up to $43.56 million of additional proceeds if the WTI exceeds the price per Bbl as specified in the agreement. Proceeds earned for any quarter are payable to us within one year and fifteen days following the end of the quarter in which additional proceeds are earned. For additional information, see Note 109, ~~Fair~~Derivative ~~Value of Financial~~ Instruments and ~~Derivative~~Fair ~~Instruments~~Value Measurements, to our Consolidated Financial Statements.

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

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. All fees owed are due on April 1 of each year. For the three and six months ended ~~March~~June 3130, 2018 ~~and 2017~~, we recorded expense of approximately $0.65 million and $1.1 million, respectively and $0.8 million and $1.6 million for the three and six months ended June 30, 2017, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of ~~March~~June 3130, 2018, approximately $01.61 million was accrued for the 2018 impact fees.

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1314. 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 ~~March~~June 3130, 2018 ~~and 2017~~, we excluded stock options to purchase 7569,~~363~~123 shares ~~and~~of ~~117~~our common stock,~~122~~ due to the 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, ~~respectively~~2017, we excluded stock options to purchase 112,348 shares of our common stock, due to the 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 ~~March~~June 3130, 2018, there were no performance-based restricted shares excluded. For the three and six months ended ~~March~~June 3130, 2017, 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 ~~months~~and six month periods ended ~~March~~June 3130, 2018 and 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. The following table sets forth the computation of basic and diluted earnings per common share:

(in thousands, except per share amounts)	Three Months Ended ~~March~~June 3130,						Six Months Ended June 30,
Numerator:	2018			2017			2018			2017
Net Income (Loss)	$	(69,793	)	$	2,683
Net Loss	$	(2,684	)	$	(9,603	)	$	(72,476	)	$	(6,920	)
Less: Preferred Stock Dividends		(598	)		(598	)		(1,196	)		(1,196	)
Net Income (Loss) Attributable to Common Shareholders	$	(70,391	)	$	2,085
Net Loss Attributable to Common Shareholders	$	(3,282	)	$	(10,201	)	$	(73,672	)	$	(8,116	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		10,~~464~~708			9,~~769~~881			10,587			9,825
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		10,~~464~~708			9,~~769~~881			10,587			9,825
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Income (Loss) Attributable to Common Shareholders	$	(6.73	)	$	0.21
Basic — Net Loss Attributable to Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)
Diluted — Net Income (Loss) Attributable to Common Shareholders	$	(6.73	)	$	0.21
Diluted — Net Loss Attributable to Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)

1415. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly owned with WPX Energy Inc. (“WPX”) and Summit Discovery Resources II, LLC and Sumitomo Corporation (collectively, “Sumitomo”), with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania. Effective as of January 1, 2018, we sold our 40% interest in RW Gathering to COG2, LLC in connection with the sale of our interest in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania (the “Westmoreland Sale”). For additional information regarding the Westmoreland Sale, see Note 45, ~~Business and~~ Oil and Gas ~~Property~~Properties ~~Dispositions~~– Joint Ventures and Divestitures, to our Consolidated Financial Statements.

During the ~~three~~six months ended ~~March~~June 3130, ~~2017~~2018, we incurred approximately $0.2 million in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2017, there were no receivables or payables due between RW Gathering and us.

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1516. IMPAIRMENT EXPENSE

For the three and six months ended ~~March~~June 3130, 2018, impairment expenses incurred were approximately $4.3 million and ~~2017~~$12.5 million, respectively, and impairment expenses incurred for the three and six months ended June 30, 2017, were approximately $83.20 million and $14.56 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first ~~three~~six months of 2018 included approximately $611.93 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Impairments of proved properties in our Westmoreland County operations totaled approximately $1.2 million during the first ~~three~~six months of 2018. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets and future development plans. Our estimates of future cash flows attributable to our oil and gas properties could decline if commodity prices decline, which may result in our incurrence of additional impairment expense. As of ~~March~~June 3130, 2018, we continued to carry the costs of undeveloped properties of approximately $~~179~~174.36 million on our Consolidated Balance Sheet, which is primarily 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 ~~three~~six months of 2017 included ~~proved properties of~~ approximately $03.8 million of 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. Impairments of proved properties in our Butler County operations totaled approximately $0.78 million during the first ~~three~~six months of 2017

1617. EXPLORATION EXPENSE

For the three and six months ended ~~March~~June 3130, 2018 ~~and 2017~~, exploration expenses ~~for~~incurred ~~continuing~~were ~~operations~~approximately ~~incurred~~$0.1 ~~were~~million and $0.3 million, respectively and approximately $0.21 million and $0.3 million for the three and six months ended June 30, 2017, respectively. Approximately $0.12 million of the expense incurred in 2018 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals. Approximately $0.12 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.

1718. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of ~~March~~June 3130, 2018, we had $600.3 million aggregate principal amount of outstanding Senior Notes, as shown in Note 78, ~~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 ~~March~~June 3130, 2018:

•

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 ~~March 31~~June 30, 2018, 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 ~~March~~June 3130, 2018 and December 31, 2017, the condensed consolidating statements of operations for the three and six months ended ~~March~~June 3130, 2018 and 2017, and the condensed consolidating statements of cash flows for the ~~three~~six months ended ~~March~~June 3130, 2018 and 2017.

3134

REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF ~~MARCH~~JUNE 3130, 2018

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			~~Rex Energy Corporation (Note Issuer)~~		Rex Energy Corporation (Note Issuer)		~~Eliminations~~		Eliminations		~~Consolidated Balance~~		Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	2528,~~087~~777		$	—		$	3	$	3	$	—	$	—	$	~~25,090~~	$	28,780
Accounts Receivable		26,345			—			802				—				27,147
Restricted Cash		—			—					33,106				—				33,106
Taxes Receivable		—			—			48				—				48
Accounts Receivable		26,961			—					1,627				—				28,588
Short-Term Derivative Instruments		5,891			—			1,841				—				7,732
Taxes Receivable		—			—					48				—				48
Inventory, Prepaid Expenses and Other		3,245			—			6,752				—				9,997
Short-Term Derivative Instruments		2,346			—					2,450				—				4,796
Total Current Assets		60,568			—			9,446				—				70,014
Inventory, Prepaid Expenses and Other		3,389			—					—				—				3,389
Property and Equipment (Successful Efforts Method)
Total Current Assets		61,473			—					37,234				—				98,707
Evaluated Oil and Gas Properties		991,617			—			—				—				991,617
Property and Equipment (Successful Efforts Method)
Unevaluated Oil and Gas Properties		179,297			—			—				—				179,297
Evaluated Oil and Gas Properties		1,062,986			—					—				—				1,062,986
Other Property and Equipment		19,792			—			—				—				19,792
Unevaluated Oil and Gas Properties		174,608			—					—				—				174,608
Wells and Facilities in Progress		52,271			—			—				—				52,271
Other Property and Equipment		20,066			—					—				—				20,066
Pipelines		16,803			—			—				—				16,803
Wells and Facilities in Progress		2,552			—					—				—				2,552
Total Property and Equipment		1,259,780			—			—				—				1,259,780
Pipelines		16,528			—					—				—				16,528
Less: Accumulated Depreciation, Depletion and Amortization		(367,900	)		—			—				—				(367,900	)
Total Property and Equipment		1,276,740			—					—				—				1,276,740
Net Property and Equipment		891,880			—			—				—				891,880
Less: Accumulated Depreciation, Depletion and Amortization		(384,556	)		—					—				—				(384,556	)
Other Assets		35			—			—				—				35
Net Property and Equipment		892,184			—					—				—				892,184
Intercompany Receivables		—			—			1,096,898				(1,096,898	)			—
Other Assets		35			—					—				—				35
Investment in Subsidiaries – Net		(2,805	)		—			(287,208	)			290,013				—
Intercompany Receivables		—			—					1,118,701				(1,118,701	)			—
Long-Term Derivative Instruments		2,589			—			291				—				2,880
Investment in Subsidiaries – Net		(2,805	)		—					(287,208	)			290,013				—
Deferred Tax Assets - Long Term		—			—			130				—				130
Long-Term Derivative Instruments		1,463			—					—				—				1,463
Total Assets	$	952,267		$	—		$	819,557			$	(806,885	)		$	964,939
Deferred Tax Assets - Long Term		—			—					130				—				130
LIABILITIES AND STOCKHOLDERS’ EQUITY
Total Assets	$	952,350		$	—				$	868,857			$	(828,688	)		$	992,519
Current Liabilities
LIABILITIES AND STOCKHOLDERS’ EQUITY
Accounts Payable	$	70,394		$	—		$	—			$	—			$	70,394
Current Liabilities
Current Maturities of Long-Term Debt		2,082			—			867,115				—				869,197
Accounts Payable	$	32,679		$	—				$	50,000			$	—			$	82,679
Accrued Liabilities		22,478			—			26,765				—				49,243
Current Maturities of Long-Term Debt		—			—				$	261,315				—				261,315
Short-Term Derivative Instruments		11,706			—			52,965				—				64,671
Debtor-in Possession Term Loan Payable		—			—					35,000				—				35,000
Total Current Liabilities		106,660			—			946,845				—				1,053,505
Accrued Liabilities		18,074			—					12,862				—				30,936
Long-Term Derivative Instruments		10,576			—			—				—				10,576
Short-Term Derivative Instruments		19,095			—					—				—				19,095
Other Long-Term Debt		7,972			—			—				—				7,972
Total Current Liabilities		69,848			—					359,177				—				429,025
Other Deposits and Liabilities		6,866			—			—				—				6,866
Long-Term Derivative Instruments		12,075			—					—				—				12,075
Future Abandonment Cost		8,~~355~~626			—			—		—		—		—		~~8,355~~		8,626
Intercompany Payables		1,092,492			4,406			—				(1,096,898	)			—
Liabilities Subject to Compromise		37,230			—					630,394				—				667,624
Total Liabilities		1,232,921			4,406			946,845				(1,096,898	)			1,087,274
Intercompany Payables		1,114,295			4,406					—				(1,118,701	)			—
Stockholders’ Equity
Total Liabilities		1,242,074			4,406					989,571				(1,118,701	)			1,117,350
Preferred Stock		—			—			1				—				1
Stockholders’ Equity
Common Stock		—			—			11				—				11
Preferred Stock		—			—					1				—				1
Additional Paid-In Capital		177,143			—			654,534				(177,143	)			654,534
Common Stock		—			—					11				—				11
Accumulated Deficit		(457,797	)		(4,406	)		(781,834	)			467,156				(776,881	)
Additional Paid-In Capital		177,143			—					654,721				(177,143	)			654,721
Total Stockholders’ Equity		(280,654	)		(4,406	)		(127,288	)			290,013				(122,335	)
Accumulated Deficit		(466,867	)		(4,406	)				(775,447	)			467,156				(779,564	)
Total Liabilities and Stockholders’ Equity	$	952,267		$	—		$	819,557			$	(806,885	)		$	964,939
Total Stockholders’ Equity		(289,724	)		(4,406	)				(120,714	)			290,013				(124,831	)
Total Liabilities and Stockholders’ Equity	$	952,350		$	—				$	868,857			$	(828,688	)		$	992,519

3235

REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED ~~MARCH~~JUNE 3130, 2018

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	6575,~~025~~155		$	—	$	—		$	—		$	6575,~~025~~155
Other Operating Revenue		43			—		—			—			43
TOTAL OPERATING REVENUE		6575,~~029~~158			—		—			—			6575,~~029~~158
OPERATING EXPENSES
Production and Lease Operating Expense		3336,~~846~~756			—		—			—			3336,~~846~~756
General and Administrative Expense		54,~~506~~235			—		~~1,019~~187			—			64,~~525~~422
Loss on Disposal of Assets		647			—		—			—			647
Impairment Expense		4,334			—		—			—			4,334
Impairment Expense		8,168			—		—			—			8,168
Exploration Expense		122			—		—			—			122
Exploration Expense		228			—		—			—			228
Depreciation, Depletion, Amortization and Accretion		16,953			—		—			—			16,953
Depreciation, Depletion, Amortization and Accretion		15,128			—		—			—			15,128
Other Operating Expense		1,492			—		—			—			1,492
Other Operating Expense		203			—		—			—			203
TOTAL OPERATING EXPENSES		63,892			—		187			—			64,079
TOTAL OPERATING EXPENSES		63,726			—		1,019			—			64,745
INCOME (LOSS) FROM OPERATIONS		11,266			—		(187	)		—			11,079
INCOME (LOSS) FROM OPERATIONS		1,303			—		(1,019	)		—			284
OTHER INCOME (EXPENSE)
Interest Expense		(~~670~~662	)		—		(2113,~~977~~456	)		—			(2214,~~647~~118	)
(Loss) Gain on Derivatives, Net		5(18,~~325~~413	)		—		~~(51~~4,~~751~~085	)		—			(4614,~~426~~328	)
Other Expense		(1,004	)		—		—			—			(1,004	)
Other (Expense) Income		53			—		(14,005	)		—			(13,952	)
Income From Equity in Consolidated Subsidiaries		—			—		4,954			(4,954	)		—
Reorganization Items, Net		(1,314	)		—		29,949			—			28,635
TOTAL OTHER INCOME (EXPENSE)		3,651			—		(68,774	)		(4,954	)		(70,077	)
Loss from Equity in Consolidated Subsidiaries		—			—		(9,070	)		9,070			—
INCOME (LOSS) BEFORE INCOME TAX		4,954			—		(69,793	)		(4,954	)		(69,793	)
TOTAL OTHER INCOME (EXPENSE)		(20,336	)		—		(2,497	)		9,070			(13,763	)
Income Tax Benefit		—			—		—			—			—
LOSS BEFORE INCOME TAX		(9,070	)		—		(2,684	)		9,070			(2,684	)
NET INCOME (LOSS)	$	4,954		$	—	$	(69,793	)	$	(4,954	)	$	(69,793	)
Income tax Benefit		—			—		—			—			—
NET LOSS	$	(9,070	)	$	—	$	(2,684	)	$	9,070		$	(2,684	)
Preferred Stock Dividends		—			—		(598	)		—			(598	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	4,954		$	—	$	(70,391	)	$	(4,954	)	$	(70,391	)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(9,070	)	$	—	$	(3,282	)	$	9,070		$	(3,282	)

3336

REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2018

($ in Thousands)

	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)		Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	140,180	$	—	$	—	$	—	$	140,180
Other Operating Revenue		7		—		—		—		7
TOTAL OPERATING REVENUE		140,187		—		—		—		140,187
OPERATING EXPENSES
Production and Lease Operating Expense		70,602		—		—		—		70,602
General and Administrative Expense

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