Rex Energy 10-K 13 Apr 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Apr. 06, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	REXX
Entity Registrant Name	REX ENERGY CORP
Entity Central Index Key	1,397,516
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,708,287
Entity Public Float			$ 46,993,210

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents	$ 15,247	$ 3,697
Accounts Receivable	25,974	25,448
Taxes Receivable	2,049	211
Short-Term Derivative Instruments	8,008	1,873
Inventory, Prepaid Expenses and Other	4,614	2,546
Total Current Assets	55,892	33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,086,625	1,053,461
Unevaluated Oil and Gas Properties	186,523	215,794
Other Property and Equipment	19,640	21,401
Wells and Facilities in Progress	38,660	21,964
Pipelines	16,803	18,029
Total Property and Equipment	1,348,251	1,330,649
Less: Accumulated Depreciation, Depletion and Amortization	(463,899)	(475,205)
Net Property and Equipment	884,352	855,444
Other Assets	44	2,492
Long-Term Derivative Instruments	1,719	2,212
Deferred Tax Assets - Long Term	130
Total Assets	942,137	893,923
Current Liabilities
Accounts Payable	62,354	40,712
Current Maturities of Long-Term Debt	834,325	764
Accrued Liabilities	45,218	37,207
Short-Term Derivative Instruments	14,892	25,025
Total Current Liabilities	956,789	103,708
Noncurrent Liabilities
Long-Term Derivative Instruments	14,249	7,227
Long-Term Debt		751,946
Other Long-Term Debt	8,156	3,409
Other Deposits and Liabilities	7,153	8,671
Future Abandonment Cost	9,352	8,736
Total Liabilities	995,699	883,697
Commitments and Contingencies (See Note 7)
Stockholders’ Equity (Deficit)
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on December 31, 2017 and 2016.	1	1
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 10,244,394 shares issued and outstanding on December 31, 2017 and 9,787,146 shares issued and outstanding on December 31, 2016	10	10
Additional Paid-In Capital	652,917	650,669
Accumulated Deficit	(706,490)	(640,454)
Total Stockholders’ Equity (Deficit)	(53,562)	10,226
Total Liabilities and Stockholders’ Equity (Deficit)	$ 942,137	$ 893,923

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Preferred Stock, par value	$ 0.001	$ 0.001
Preferred Stock, shares authorized	100,000	100,000
Preferred Stock, shares issued	3,987	3,987
Preferred Stock, shares outstanding	3,987	3,987
Common Stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common Stock, shares issued	10,244,394	9,787,146
Common Stock, shares outstanding	10,244,394	9,787,146

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales									$ 205,246		$ 139,000		$ 138,707
Other Revenue									20		17		42
TOTAL OPERATING REVENUE	$ 57,758	$ 47,975	$ 47,462	$ 52,071	$ 48,027	$ 34,039	$ 31,265	$ 25,686	205,266		139,017		138,749
OPERATING EXPENSES
Production and Lease Operating Expense									120,794		104,699		93,892
General and Administrative Expense									17,858		20,621		26,694
Gain on Disposal of Assets									(1,428)		(4,121)		(540)
Impairment Expense	4,928	11,877	3,032	1,546	29,279	9,563	25,136	10,641	21,383		74,619		283,244
Exploration Expense									527		2,178		2,617
Depreciation, Depletion, Amortization and Accretion									59,028		62,874		85,844
Other Operating Expense									611		10,754		5,603
TOTAL OPERATING EXPENSES									218,773		271,624		497,354
LOSS FROM OPERATIONS									(13,507)		(132,607)		(358,605)
OTHER INCOME (EXPENSE)
Interest Expense									(48,826)		(43,519)		(47,783)
Gain (Loss) on Derivatives, Net									(1,347)		(32,515)		60,176
Other Expense									(261)		(2,124)		(129)
Debt Exchange Expense											(9,063)
Gain (Loss) on Extinguishments of Debt									(3,029)		24,627
Loss on Equity Method Investments													(411)
TOTAL OTHER INCOME (EXPENSE)									(53,463)		(62,594)		11,853
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(66,970)		(195,201)		(346,752)
Income Tax Benefit (Expense)									2,728		(2,436)		(6,030)
NET LOSS FROM CONTINUING OPERATIONS					(75,598)	(16,477)	(52,911)	(52,651)	(64,242)		(197,637)		(352,782)
Income (Loss) From Discontinued Operations, Net of Income Taxes											20,922		(8,251)
NET LOSS									(64,242)		(176,715)		(361,033)
Net Income Attributable to Noncontrolling Interests													2,245
NET LOSS ATTRIBUTABLE TO REX ENERGY	(10,788)	(46,534)	(9,603)	2,683	(67,395)	5,415	(54,594)	(60,141)	(64,242)		(176,715)		(363,278)
Preferred Stock Dividends	(598)	(598)	(598)	(598)	(650)	(613)	(1,723)	(2,105)	(2,392)		(5,091)		(9,660)
Effect of Preferred Stock Conversions					668		72,316				72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (11,386)	$ (47,132)	$ (10,201)	$ 2,085	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	$ (66,634)		$ (108,822)		$ (372,938)
Earnings per common share:
Basic – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders					$ (7.77)	$ (1.89)	$ 2.45	$ (9.78)	$ (6.73)	[1]	$ (16.37)	[1]	$ (66.64)	[1]
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders					0.84	2.41	(0.23)	(1.34)			2.64	[1]	(1.93)	[1]
Basic – Net Loss Attributable to Rex Energy Common Shareholders	$ (1.13)	$ (4.76)	$ (1.03)	$ 0.21	$ (6.93)	$ 0.52	$ 2.22	$ (11.12)	$ (6.73)	[1]	$ (13.73)	[1]	$ (68.57)	[1]
Basic – Weighted Average Shares of Common Stock Outstanding	10,049	9,906	9,881	9,769	9,740	9,080	7,180	5,600	9,902		7,926		5,439
Diluted – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders					$ (7.77)	$ (1.89)	$ 2.45	$ (9.78)	$ (6.73)	[1]	$ (16.37)	[1]	$ (66.64)	[1]
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders					0.84	2.41	(0.23)	(1.34)			2.64	[1]	(1.93)	[1]
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$ (1.13)	$ (4.76)	$ (1.03)	$ 0.21	$ (6.93)	$ 0.52	$ 2.22	$ (11.12)	$ (6.73)	[1]	$ (13.73)	[1]	$ (68.57)	[1]
Diluted – Weighted Average Shares of Common Stock Outstanding	10,049	9,906	9,881	9,769	9,740	9,080	7,180	5,600	9,902		7,926		5,439
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Consolidated Statements of Chan

Consolidated Statements of Changes in Noncontrolling Interests and Stockholders' Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit	Rex Energy Stockholders' Equity (Deficit)	Noncontrolling Interest
Balance at Dec. 31, 2014	$ 531,373	$ 5	$ 1	$ 617,875	$ (90,749)	$ 527,132	$ 4,241
Balance (in shares) at Dec. 31, 2014		5,418	16
Equity Based Compensation	6,469			6,469		6,469
Issuance of Restricted Stock, Net of Forfeitures (in shares)		157
Capital Distributions	(830)						(830)
Change in Ownership of Noncontrolling Interests	(6,088)			(432)		(432)	(5,656)
Dividends Declared on Preferred Stock	(9,660)				(9,660)	(9,660)
Net Income (Loss)	(361,033)				(363,278)	(363,278)	$ 2,245
Balance at Dec. 31, 2015	160,231	$ 5	$ 1	623,912	(463,687)	160,231
Balance (in shares) at Dec. 31, 2015		5,574	16
Equity Based Compensation	2,919			2,919		2,919
Issuance of Common Stock in Debt Exchange	$ 6,412	$ 1		6,411		6,412
Issuance of Common Stock in Debt Exchange (in shares)	800	841
Issuance of Common Stock for Debt Extinguishments	$ 17,378	$ 3		17,375		17,378
Issuance of Common Stock for Debt Extinguishments (in shares)		2,352
Preferred Dividends in Arrears Paid in Common Shares				52	(52)
Preferred Stock Dividends in Arrears Paid in Common Shares ( in shares)		6
Issuance of Restricted Stock, Net of Forfeitures	1			1		1
Issuance of Restricted Stock, Net of Forfeitures (in shares)		82
Conversion of Preferred Stock to Common Stock		$ 1		(1)
Conversion of Preferred Stock to Common Stock (in shares)		931	(12)
Net Income (Loss)	(176,715)				(176,715)	(176,715)
Balance at Dec. 31, 2016	10,226	$ 10	$ 1	650,669	(640,454)	10,226
Balance (in shares) at Dec. 31, 2016		9,787	4
Equity Based Compensation	1,231			1,231		1,231
Issuance of Common Stock for Debt Extinguishments	$ 467			467		467
Issuance of Common Stock for Debt Extinguishments (in shares)		84
Preferred Dividends in Arrears Paid in Common Shares				598	(598)
Preferred Stock Dividends in Arrears Paid in Common Shares ( in shares)	300	314
Issuance of Restricted Stock, Net of Forfeitures (in shares)		59
Effect of Reverse Stock Split	$ (48)			(48)		(48)
Dividends Declared on Preferred Stock	(1,196)				(1,196)	(1,196)
Net Income (Loss)	(64,242)				(64,242)	(64,242)
Balance at Dec. 31, 2017	$ (53,562)	$ 10	$ 1	$ 652,917	$ (706,490)	$ (53,562)
Balance (in shares) at Dec. 31, 2017		10,244	4

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ (64,242)	$ (176,715)	$ (361,033)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Loss on Equity Method Investments			411
Depreciation, Depletion, Amortization and Accretion	59,028	67,975	104,822
Loss (Gain) on Derivatives	1,347	32,515	(60,176)
Cash Settlements of Derivatives	(10,100)	32,571	55,793
Non-Cash Dry Hole Expense	13	905	330
Equity-based Compensation Expense	1,231	2,959	6,549
Impairment Expense	21,383	78,162	345,775
Amortization of Debt Issuance Costs	1,165	1,640	2,045
Amortization of Bond Discounts and Premiums		(100)	(381)
Non-cash Interest Expense related to Debt Restructurings and Exchanges	14,063	19,603
Loss (Gain) on Extinguishment of Debt	3,029	(24,627)
Gain on Disposal of Assets	(1,428)	(34,651)	(521)
Gain on Sale of Water Solutions			(57,778)
Deferred Income Tax Benefit	(130)
Other Non-cash Income (Expense)	471	22	(564)
Changes in operating assets and liabilities
Accounts Receivable	5,258	(6,414)	21,679
Taxes Receivable	(1,839)
Inventory, Prepaid Expenses and Other Assets	(2,060)	906	(568)
Accounts Payable and Accrued Liabilities	14,558	2,795	(22,955)
Other Assets and Liabilities	(3,259)	(1,950)	(2,543)
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES	38,488	(4,404)	30,885
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management			58
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	31,704	40,884	77,226
Proceeds from Joint Venture for reimbursement of capital Costs		19,461	16,611
Acquisitions of Undeveloped Acreage	(3,805)	(6,712)	(28,242)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(113,411)	(48,982)	(221,099)
NET CASH (USED) PROVIDED BY INVESTING ACTIVITIES	(85,512)	4,651	(155,446)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt, Lines of Credit and Term Loan	217,000	71,400	229,314
Repayments of Long-Term Debt, Lines of Credit and Term Loan	(145,170)	(65,230)	(108,335)
Repayments of Loans and Other Notes Payable	(1,306)	(828)	(1,519)
Debt Issuance Costs	(10,754)	(2,983)	(1,414)
Distributions by the Partners of Consolidated Subsidiary			(830)
Payment of Preferred Dividends in Arrears	(1,196)		(9,660)
NET CASH PROVIDED BY FINANCING ACTIVITIES	58,574	2,359	107,556
NET INCREASE (DECREASE) IN CASH	11,550	2,606	(17,005)
CASH AND CASH EQUIVALENTS – BEGINNING	3,697	1,091	18,096
CASH AND CASH EQUIVALENTS – ENDING	15,247	3,697	1,091
Cash and Cash Equivalents	15,247	3,697	1,091
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of Capitalized Interest	22,382	30,805	47,628
Net Cash Paid (Received) for Income Taxes	1,839	29	(502)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations		1,346	14,210
NON-CASH ACTIVITIES
Proceeds held in Escrow - non cash component of Gain on Sale of Assets	5,000
Increase (Decrease) in Accounts Payable and Accrued Liabilities for Capital Expenditures	14,637	712	$ (11,703)
Net Increase in Property and Equipment - Capital Lease Financing	7,170
Decrease in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions	(879)	(47,182)
Decrease in Bond Interest Payable due to Debt to Equity Conversions	(12)	(892)
Increase in Common Stock Additional Paid-In Capital due to Debt to Equity Conversions	467	17,378
Preferred Dividends in Arrears Paid in Common Shares	598
Illinois Basin Operations
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin	$ (1,216)	$ (2,936)

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent condensate, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in oil, NGL and natural gas properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Our term loan agreement (“Term Loan”) requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and a maximum net senior secured debt to EBITDAX ratio. EBITDAX is a non-GAAP measure used by our management team and by other users of our financial statements. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data - Non-GAAP Financial Measures.” If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties. Notice of Delisting from the Nasdaq Stock Market Our common stock has been listed on the Nasdaq Capital Market, where it had been listed since December 2016 after previously being listed on the Nasdaq Global Select Market. On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department of 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 requested an appeal before the Nasdaq Hearings Panel. We did not appeal this determination and the time period in which to appeal has lapsed. Following the expected delisting of our common stock from Nasdaq, our common stock may be eligible for quotation on the OTCBB or OTC Markets Group’s Pink marketplace. Trading on the OTCBB or Pink marketplace may occur only if a market maker applies to quote our common stock and we are current in our reporting obligations under the Securities Exchange Act of 1934. Once our common stock is delisted from Nasdaq, there can be no assurance that a market maker will apply to quote our common stock or that our common stock then will be eligible for quotation on the OTCBB or the Pink marketplace. Going Concern As of April 13, 2018, the date we filed our Consolidated Financial Statements with the Securities and Exchange Commission on Form 10-K for the annual reporting period ended December 31, 2017, we have not We entered into a forbearance agreement with the requisite lenders under our senior term loan facility on April 2, 2018. The forbearance agreement does 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 agreement specifies that the lenders will forbear from taking any enforcement actions during the forbearance period, which extends through April 16, 2018, unless earlier terminated, but does not prevent the administrative agent under the term loan agreement from accelerating amounts owed under the term loan agreement. If we are unsuccessful in negotiating a restructuring transaction prior to the April 16, 2018 expiration of the forbearance period, or are otherwise unable to further negotiate or extend the forbearance period, the agreement of the lenders to forbear from taking any enforcement actions with respect to the events of default will immediately and automatically cease. If the lenders for the term loan agreement and subsequently the noteholders, accelerate the Company’s outstanding indebtedness (approximately $789.8 million as of December 31, 2017), it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts. The Company is currently in discussions with various stakeholders and is pursuing or considering a number of actions including: (i) obtaining additional sources of capital from potential outside investors, negotiating modifications of certain terms of both the second lien notes and the senior term loan facility, restructuring current debt obligations through debt for equity exchanges, or any combination thereof; (ii) pursuing in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from its lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. There can be no assurance that sufficient liquidity can be obtained from one or more of these actions or that these actions can be consummated within the period needed. The ability to conclude a successful negotiation with our lenders and note holders to restructure our debt obligations has been deemed to be outside of our control in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 205-40, Going Concern The events of default and significant risks and uncertainties described above raise substantial doubt about the Company’s 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. 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 effect of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis. Discontinued Operations Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 4, Discontinued Operations/Assets Held for Sale During December 2014, our board of directors approved and committed to a plan to sell Water Solutions Holdings, LLC and its related subsidiaries (“Water Solutions”), of which we owned a 60% interest. The sale of Water Solutions closed in July 2015. As a result, the results of operations of Water Solutions have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for the year ended December 31, 2015. As of December 31, 2017 and 2016, we had no assets, liabilities or continuing cash flows related to Water Solutions. In June 2016, we entered into a purchase and sale agreement to divest all of our Illinois Basin assets and operations. The sale closed in August 2016, with an effective date of July 1, 2016. As a result of this transaction, the results of operations of our Illinois Basin operations have been classified as Discontinued Operations in the accompanying Consolidated Statements of Operations as of December 31, 2016 and 2015. As of December 31, 2017 and 2016, we have a derivative asset of $1.7 million and $2.9 million recorded, respectively, representing the fair value of contingent consideration payments as specified in the Illinois Basin sales agreement. For additional information, see Note 4, Discontinued Operations

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. Estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved natural gas, NGL and oil reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of condensate and natural gas, interest rates and our ability to generate future income. Cash and Cash Equivalents We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2017 and 2016, our Cash and Cash Equivalents consisted of only cash. Accounts Receivable Our trade accounts receivable, which are primarily from natural gas, NGLs and condensate sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2017 and 2016 were $0.1 million and $0.1 million, respectively. To the extent actual quantities and values of natural gas, NGLs and condensate are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets. At December 31, 2017, we carried approximately $22.9 million in production receivable, of which approximately $19.3 million were production receivables due from our three largest purchasers. At December 31, 2016, we carried approximately $22.2 million in production receivables, of which approximately $17.5 million were production receivables due from three purchasers. In addition, we carried approximately $2.5 million in receivables at December 31, 2017 and $2.7 million at December 31, 2016 that was in relation to our joint operations with Sumitomo Corporation, Benefit Street Partners, LLC and ArcLight Capital Partners, LLC. Inventory Inventory is valued at the lower of cost or market value and consists of our ownership interest in NGLs and condensate held in terminal tanks located in the field. NGL and condensate cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory. Natural Gas , NGLs, and Oil Property, Depreciation and Depletion We account for natural gas, NGL and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proven natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of condensate, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2017, 2016 and 2015, we capitalized interest costs of $1.7 million, $2.7 million and $7.7 million, respectively. Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable natural gas and oil are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years. We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future natural gas, NGL and condensate prices are based on forward strip prices for NYMEX oil and various natural gas markets that are relevant to our operations. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved natural gas and oil properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved natural gas, NGL and condensate properties, we analyze the level and success of current development, changes in future development plans and changes in market value. If it is determined that it is unlikely for an unproved property to be successfully developed prior to the lease expiration or extension, an impairment of the respective unproved property is recognized in the period in which that determination is made. Performing the impairment evaluations requires use of judgment since the results are dependent on future events, including the timing of future capital expenditures, production and the intent to develop properties, among others. We recognized approximately $21.4 million, $74.6 million and $283.2 million of impairment from continuing operations on certain natural gas, NGL and condensate properties for the years ended December 31, 2017, 2016 and 2015, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depletion are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain. Natural Gas, NGL and Condensate Reserve Quantities Our estimate of proved reserves is based on the quantities of natural gas, NGLs and condensate that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2017 and 2016, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our natural gas, NGLs, and condensate reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineers estimate reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production. Future Abandonment Cost Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Accretion expense from continuing operations during the years ended December 31, 2017, 2016 and 2015 totaled approximately $1.9 million, $1.0 million and $1.0 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2017 and 2016, approximately $0.6 million and $1.1 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Liabilities on our Consolidated Balance Sheets. During 2017 and 2016, we recognized an increase of $0.8 million and $1.9 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells. December 31, 2017 (in thousands) December 31, 2016 (in thousands) Beginning Balance $ 9,865 $ 11,934 Asset Retirement Obligation Incurred 1,061 575 Asset Retirement Obligation Settled (3,187 ) (671 ) Asset Retirement Obligation Cancelled or Sold Properties (549 ) (4,876 ) Asset Retirement Obligation Revision of Estimated Obligation 834 1,918 Asset Retirement Obligation Accretion Expense 1,915 985 Total Future Abandonment Costs $ 9,939 $ 9,865 Revenue Recognition Natural gas, NGLs, and condensate revenue is recognized when the natural gas, NGLs, or condensate is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of condensate sales, title is transferred to the purchaser when the condensate leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, wellhead gas volumes are first processed through various third-party gas processing facilities to separate the raw (“wet”) gas into NGL products and natural gas. Title to NGL and natural gas products transfers to the purchaser when the separated product volumes are metered for sale either at the exit flange of a processing facility, or the inlet flange of a purchaser’s designated delivery point. Sales prices for purchased volumes are defined in sales contracts and are readily determinable based on certain publicly available indices. Our commodity purchasers have historically made payment for natural gas, NGL and condensate purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. To the extent actual quantities and values of natural gas, NGLs and condensate are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in our Consolidated Balance Sheets, and as natural gas, NGL, and condensate Sales in our Consolidated Statements of Operations. Effective January 1, 2018, we adopted ASC 606, Revenue from Contracts with Customers. Recently Issued Accounting Pronouncements – Revenue Recognition Derivative Instruments We use put and call options (collars), fixed rate swap contracts, puts, basis swaps and three-way collars to manage price risks in connection with the sale of natural gas, NGLs, and condensate. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third parties. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2017, 2016 and 2015 we did not have any derivative instruments designated for hedge accounting. For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on natural gas, NGL, and oil production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments Contingent Liabilities A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Income Taxes We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to oil and gas properties and other taxable differences. Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rates. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized. This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position. The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 11, Income Taxes, Stock-based Compensation We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 15, Employee Benefit and Equity Plans, In March 2016, the Financial Account Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting Earnings per Common Share Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2017, we had 10,244,394 common shares outstanding, 86,331 options outstanding and 2,050 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 200,475 restricted stock awards, of which approximately 38,261 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share Recent Accounting Pronouncements From May 2014 through September 2017, the FASB issued several ASUs revising certain revenue accounting standards, codified together as Accounting Standards Codification (“ASC”) 606 – Revenue from Contracts with Customers The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. is effective for interim and annual periods beginning af permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented and any cumulative effect of applying the standard recognized in the earliest period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. We have adopted a the modified retrospective method. This allows us t new contracts entered into after January 1, 2018 existing contracts for w revenue not expect the standard to res financial position implemen business processes, systems, and controls to support recogn . disclosures will be describe the nature, amount, timing and uncertainty of revenue and cash flows f and remaining perf During 2016 and 2017, we evaluated our contracts with customers under ASC 606. We have determined that adoption of the standard would not result in any material change to the timing or method of recognizing revenue for our natural gas, NGL, and condensate commodity sales under contracts with our customers. The impact of adopting ASC 606 relates primarily to contract arrangements wherein title to the good or service and risk of loss transfer from seller to purchaser at different points. Our sales contracts with customers specify that title to purchased commodity volumes and the risk of loss associated with those goods transfers to the purchaser at the same point in time, which is consistent with the ASC 606 revenue recognition model. Our analysis of contract performance obligations and transaction pricing structures under ASC 606 is not materially different from our obligations and pricing structures identified under our current revenue recognition model. ASC 606 requires evaluation of contracts with customers to determine whether the selling party in a contract for goods or services is acting in the capacity of the Principal or as an Agent, as defined in the standard. This determination is then applied to evaluate whether revenues earned from sales to a customer are to be reported in the statement of operations as gross revenue receipts (in our instance commodity volumes sold multiplied by the contract specified sales price), or reported net of various costs incurred by the seller to fulfill the performance obligation. To produce the various saleable commodities that we supply to our customers from our wellhead wet gas and to transport products to the physical points of sale, we incur expenses including gas plant processing fees, gathering and compressions fees, transportation charges, and fees for pipeline capacity commitments. We have determined that we are the principal in all our current commodity sales contracts, and accordingly we record sales revenue at the gross sales price received. Our expense associated with processing and delivering the products to our buyers are reported as components of Production and Lease Operating Expense In February 2016, the FASB issued ASU 2016-02, Leases • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

Business and Oil and Gas Proper

Business and Oil and Gas Property Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Business and Oil and Gas Property Acquisitions and Dispositions	3. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS Dispositions Water Solutions In December 2014, our board of directors approved a formal plan to sell Water Solutions, of which we owned a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.6 million. The transaction is recorded as Discontinued Operations. ArcLight Capital Partners, LLC On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight participated and funded 35.0% of the estimated well costs for the designated wells. We received total consideration for the transaction of approximately $67.6 million, of which $16.6 million was received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. All wells have been drilled and placed in service. If the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest may revert back to us, leaving ArcLight with a 17.5% working interest. The ArcLight transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized. Due to the fixed payment per well structure of the transaction, payments by ArcLight are treated as gains or losses, as appropriate, on a well-by-well basis for tax purposes. Benefit Street Partners, LLC On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised their option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million, with approximately $134.0 million committed as of December 31, 2017. BSP has paid for their interest in the elected wells as of December 31, 2017. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of December 31, 2017, all 45 committed wells were in line and producing. The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized. Diversified Oil & Gas, LLC On May 20, 2016, we entered into a Purchase and Sale Agreement (“PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $0.1 million. Included in the sale were approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016 due to the elimination of our future abandonment liability associated with wells and pipelines sold to DOG. The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale. Illinois Basin Operations On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell agreed to purchase all of Rex’s oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June 2016 and received the additional proceeds of approximately $38.5 million at closing in August 2016. An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of December 31, 2017, the first five of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds relate to those measurement periods. As of December 31, 2017, we have the potential to receive up to $5.4 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 10, Fair Value of Financial Instruments and Derivative Instruments Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays). Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day. The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations. As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale”, and our assets and operations in the Illinois Basin are reported as Discontinued Operations. Sale of Warrior South 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, to be released in January 2018 net of post-closing adjustments. The proceeds held in escrow were released to us in December 2017 in the amount of $5.0 million, net of post-closing adjustments. 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 initially 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.

Discontinued Operations_Assets

Discontinued Operations/Assets Held For Sale	12 Months Ended
	Dec. 31, 2017
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations/Assets Held For Sale	4. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE Water Solutions Holdings, LLC As described in Note 3 above, during 2015 we sold Water Solutions pursuant to a purchase and sale agreement with American Water. As of December 31, 2017 and 2016, we had no assets or liabilities related to Water Solutions or continuing cash flows from this region. Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. December 31, ($ in Thousands) 2017 2016 2015 Revenues: Field Services Revenue $ — $ — $ 33,086 Total Operating Revenue — — 33,086 Costs and Expenses: General and Administrative Expense — — 1,961 Depreciation, Depletion, Amortization and Accretion — — 78 Impairment Expense — — — Field Service Operating Expense — — 25,981 Gain on Disposal of Asset — — (44 ) Interest Expense — — 487 Other (Income) Expense — — (57,589 ) Total Costs and Expenses (Income) — — (29,126 ) Income from Discontinued Operations Before Income Taxes — — 62,212 Income Tax Expense — — (24,227 ) Income from Discontinued Operations, net of taxes $ — $ — $ 37,985 Illinois Basin Operations As described in Note 3 above, we sold our Illinois Basin assets and operations pursuant to a purchase and sale agreement with Campbell in August 2016. As of December 31, 2017 and 2016, we had no assets or liabilities related to the Illinois Basin or continuing cash flows from this region. Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. The sale of our Illinois Basin assets and operations does not include any of our derivative contracts or positions related to our Illinois Basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the years ended December 31, 2017, 2016 and 2015. December 31, ($ in Thousands) 2017 2016 2015 Revenues: Oil Sales $ — $ 11,282 $ 33,244 Total Operating Revenue — 11,282 33,244 Costs and Expenses: Production and Lease Operating Expense — 11,033 25,099 General and Administrative Expense — 1,002 2,741 (Gain) Loss on Disposal of Assets — (30,530 ) 63 Impairment Expense — 3,543 62,531 Exploration Expense — 143 394 Depreciation, Depletion, Amortization and Accretion — 5,100 18,900 Interest Expense — 4 23 Other (Income) Expense — 65 (14 ) Total Costs and Expenses — (9,640 ) 109,737 Income (Loss) from Discontinued Operations Before Income Taxes — 20,922 (76,493 ) Income Tax Benefit — — 30,257 Income (Loss) from Discontinued Operations, net of taxes $ — $ 20,922 $ (46,236 ) Production: Crude Oil (Bbls) — 310,388 729,251

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2017
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	5. EQUITY METHOD INVESTMENTS RW Gathering 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 26, Subsequent Events We incurred a 100% impairment charge of $17.5 million during the second quarter of 2015 related to our investment in RW Gathering (for additional information, see Note 16, Impairment Expense

Concentrations of Credit Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2017
Risks And Uncertainties [Abstract]
Concentrations of Credit Risk	6. CONCENTRATIONS OF CREDIT RISK At times during the years ended December 31, 2017 and 2016, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations. 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 counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our term loan facility. 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 settlement date. For additional information, see Note 2, Summary of Significant Accounting Policies, Fair Value of Financial Instruments and Derivative Instruments, We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2017, we carried approximately $22.9 million in production receivables, of which approximately $19.3 million were production receivables due from three purchasers. At December 31, 2016, we carried approximately $22.2 million in production receivables, of which approximately $17.5 million were production receivables due from three purchasers. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of condensate and gas sales as well as the quantity of purchasers.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	7. 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. Environmental Due to the nature of the natural gas and oil 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 to identify changes our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. We manage our exposure to environmental liabilities on properties to be acquired by conducting evaluations (both internal and using consultants) to identify existing problems and assessing the potential liability. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages cost of employees who are expected to devote a significant amount of time directly to any remediation effort. At this time we know of no significant probable or possible environmental contingent liabilities relating to our operations. Letters of Credit As of December 31, 2017 and 2016, we had posted $32.0 million and $46.5 million, respectively, in various letters of credit to secure our drilling and related operations. Approximately $31.7 million of the letters of credit outstanding at December 31, 2017 are related to firm natural gas transportation agreements. Lease Commitments At December 31, 2017 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.8 million, $0.9 million and $1.0 million for the years ended December 31, 2017, 2016 and 2015, respectively. Lease commitments by year for each of the next five years are presented in the table below. ($ in Thousands) 2018 $ 1,013 2019 1,020 2020 888 2021 475 2022 485 Thereafter — Total $ 3,881 Capacity Reservation We are a party to a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $16.6 million in 2018, $16.6 million in 2019, $16.6 million in 2020, $16.6 million in 2021, $16.6 million in 2022 and $65.0 million thereafter, assuming our average working interest in the region of approximately 53.2%. For the years ended December 31, 2017, 2016 and 2015, we incurred capacity reservation charges of $5.2 million, $3.2 million and $0.6 million, respectively. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations. As we continue to develop our assets in 2018 and beyond, we expect that our capacity reservation fees will decrease. 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 of 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 December 31, 2017, our future commitment for unpurchased volumes is approximately $0.8 million. Operational Commitments We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $1.9 million in 2018. We also have contracted completions services in the Appalachian Basin. The minimum gross cost to retain these completion services is approximately $7.0 million in 2018. These costs are partially offset by other working interest owners, whose interests and share of these expenses vary from well to well. If the drilling rig is idle, the Company is solely responsible for the associated cost, unless otherwise negotiated with these other working interest owners. 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 condensate, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $377.2 million through 2029. For the years ended December 31, 2017, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing our condensate, natural gas and natural gas liquids of approximately $109.2 million, $91.7 million and $79.5 million, respectively. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2018 $ 50,313 2019 50,864 2020 49,526 2021 46,574 2022 46,139 Thereafter 464,599 Total $ 708,015 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 natural gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. For the years ended December 31, 2017, 2016 and 2015, we incurred approximately $3.6 million, $3.0 million and $3.0 million, respectively, in fees related to the natural gas impact fee. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	8. RELATED PARTY TRANSACTIONS Aircraft Services We have an oral month-to-month agreement with Charlie Brown Air Corp. (“Charlie Brown”), a New York corporation owned by Lance T. Shaner, our Chairman, regarding the use of one airplane owned or managed by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplane equal to our percentage (based upon the total number of hours of use of the airplane by us) of the monthly fixed costs for the airplane, plus a variable per hour flight rate that ranges from $700 to $1,560 per hour. For the year ended December 31, 2017, we did not pay Charlie Brown for use of the aircraft. For the years ended December 31, 2016 and 2015 we paid Charlie Brown zero and approximately $0.1 million, respectively, for the use of the aircraft, including the variable per hour cost in addition to pilot fees, maintenance, hangar rental and other miscellaneous expenses. We own a 50% membership interest in Charlie Brown Air II, LLC (“Charlie Brown II”). The other 50% is owned by Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Lance T. Shaner (“Shaner Hotel”). Charlie Brown II owns and operates an Eclipse 500 aircraft. In June 2007, Charlie Brown II borrowed approximately $1.5 million in original principal amount from BB&T Bank to purchase the aircraft. The loan currently bears interest at a rate equal to the Prime Rate as published in the Wall Street Journal. Charlie Brown II is required to make monthly payments of principal and interest of approximately $0.1 million in the aggregate annually and a final balloon payment of approximately $0.6 million at maturity in August 2019. The Company and Shaner Hotel each guarantee up to fifty percent of the principal balance of the loan. The balance of this loan as of December 31, 2017 and 2016 was approximately $0.8 million and $0.9 million, respectively. For the years ended December 31, 2017, 2016 and 2015, we paid Charlie Brown II approximately $0.2 million, $0.2 million and $0.3 million, respectively, for loan interest, services rendered and retainer fees. The business affairs of Charlie Brown II are managed by two members, appointed by each of its two owners. We have designated Thomas C. Stabley, our President and Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown II require the written consent of both managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company. Office Rental On June 27, 2012, we entered into an office lease agreement with Shaner Office Holdings, L.P., a limited partnership controlled by Lance T. Shaner. The office lease, which replaced our former headquarters office lease in State College, Pennsylvania, calls for monthly rental payments in the initial amount of $35,000 beginning on April 1, 2013, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The terms of the lease provided that the lease may be extended for up to three five-year periods following the initial five-year term, or in the alternative, that the property could be purchased outright by our exercise of a purchase option at the end of the initial five-year term. On September 15, 2017, we exercised our option to renew the lease for a five-year period beginning on January 1, 2018 and ending on December 31, 2022, and did not exercise the purchase option. For the year ended December 31, 2017, we paid Shaner Office Holdings, L.P. approximately $0.6 million in office rental payments and utilities. We account for this lease as an operating lease, subsequently recording the rental payments as General and Administrative Expense on our Consolidated Statements of Operations. Second Lien Notes In May 2017, the Lance T. Shaner Revocable Trust (which is solely controlled by Lance T. Shaner) acquired approximately $4.6 million in principal amount of our 1.00%/8.00% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) at face value in an open market purchase. As a result, Mr. Shaner is entitled to all of the rights of a holder of Second Lien Notes as described in the Indenture governing the Second Lien Notes, including the right to receive twice-yearly interest payments, and to payment of the principal amount at maturity. Bronder Technical Services From time to time, Bronder Technical Services, Inc. (“Bronder”), an electrical services contractor in which Lance T. Shaner owns a controlling interest, provides wellsite-based electrical services to the Company. The electrical work on each of the Company’s well sites is subject to a competitive bidding process. In 2017, Bronder’s bid was selected for various electrical jobs on four of the Company’s well pads. Due to this competitive bidding process, the pricing terms applicable to these projects were consistent with, or more favorable than, market rates for the type of services performed. In 2017, the Company compensated Bronder in an aggregate amount of approximately $0.3 million for these services. Rex is under no continuing obligation to use Bronder, and electrical services will continue to be awarded on a wellsite-by-wellsite basis based on price and quality of work of contractors. As of December 31, 2017, there were negligible amounts due to us from or from us to any Shaner affiliated entities. RW Gathering, LLC As of December 31, 2017, we owned a 40% interest in RW Gathering which owns gas-gathering assets that facilitate the development of our joint operations with WPX and Sumitomo (see Note 5, Equity Method Investments Water Solutions We incurred approximately $6.1 million in gross water transfer and equipment rental expenses that were charged to us from Water Solutions during 2015 (through the date of sale in July 2015). Of the amounts incurred, we eliminated approximately $4.7 million in consolidation for the year 2015. As of December 31, 2015, we had no payables owed to Water Solutions for work performed during the period due to sale of our interest in Water Solutions during third quarter 2015. As of December 31, 2015, we classified the operations of Water Solutions as Discontinued Operations. See note 4, Discontinued Operations/Assets Held for Sale

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	9. LONG-TERM DEBT Term Loan On April 28, 2017 (the “Effective Date”), we entered into a term loan agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent, 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 are currently limited to $300,000,000. Amounts borrowed and repaid may not be re-borrowed. The maturity date for the loans under the Term Facility and the loans drawn under the Delayed Draw Term Facility is the earlier of (a) April 28, 2021 and (b) the date that is six months prior to the maturity of our 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. The commitments under the Delayed Draw Term Facility expire if not drawn prior to the earlier of (a) April 28, 2018 (which date may be extended for one year with lender consent) and (b) the date upon which we terminate such commitments. As of December 31, 2017, we had $189.5 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 $1.4 million in OID related to the Delayed Draw Term Facility. From April 28, 2017 through December 31, 2017, we amortized $0.7 million of debt issuance costs and $1.0 million of OID. The amortization of debt issuance costs and OID are reported as Interest Expense in our Consolidated Statement of Operations. Borrowings under the Term Loan bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. The “Adjusted LIBO Rate” is equal to the product of the three month LIBOR rate multiplied by the statutory reserve rate. At December 31, 2017 the weighted average interest rate on the Company’s Term Loan was 10.2%. Interest expense on the Term Loan for the year ended December 31, 2017 was approximately $11.0 million. Upon the occurrence and continuance of an Event of Default all outstanding loans shall bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable on the last business day of each March, June, September and December. Under the Term Loan, we will pay a 3.5% commitment fee on any unused portion of the Delayed Draw Term Facility. The Term Loan requires us to prepay the loans with 100% of the net cash proceeds received from certain asset sales, swap terminations, incurrences of borrowed money indebtedness, casualty events and equity issuances, subject to certain exceptions and specified reinvestment rights. Prepayments based on 75% of excess cash flow, (“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. There were no prepayments made during 2017. The Term Loan contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividend payments, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions. The Term Loan also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after December 31, 2017, the PDP Coverage Ratio (as defined in the Term Loan) will not be less than 1.65 to 1.00; (2) as of the last day of any fiscal quarter ending on or after March 31, 2017, the ratio of Net Senior Secured Debt (as defined in the Term Loan) as of such date to EBITDAX (as defined in the Term Loan) for the period of four fiscal quarters then ending on such day will not be greater than 3.25 to 1.00 (provided that EBITDAX for the four fiscal quarters ending on (i) March 31, 2017 shall be EBITDAX for the fiscal quarter then ending multiplied by four and (ii) June 30, 2017 shall be EBITDAX for the two fiscal quarters then ending multiplied by two); and (3) as of the last day of any fiscal quarter ending on or after September 30, 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 December 31, 2017, our PDP Coverage Ratio was 2.63 to 1.00, Net Senior Secured Debt to EBITDAX Ratio was 3.00 to 1.00 and EBITDAX to Cash Interest Expense was 2.60 to 1.00. Our obligations under the Credit Agreement may be accelerated upon the occurrence of an Event of Default (as such term is defined in the Term Loan). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the Term Loan). Obligations under the Term Loan are secured by mortgages on our oil and gas properties. In connection with the Term Loan, we, including our wholly owned subsidiaries, Rex Energy I, LLC, Rex Energy Operating Corp., PennTex Resources Illinois, Inc., Rex Energy IV, LLC, and R.E. Gas Development, LLC (collectively, the “Guarantors” and together with us, the “Grantors”), entered into an amended and restated guaranty and collateral agreement, dated as of April 28, 2017, in favor of the Collateral Agent for the lenders from time to time party to the Term Loan, the secured swap parties and the Issuing Bank (the “Guaranty and Collateral Agreement”). Pursuant to the Guaranty and Collateral Agreement, each of the Guarantors, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Term Loan. In addition, each Grantor granted, as security for the prompt and complete payment and performance when due of such Grantor’s obligations, a security interest in substantially all of its assets, including equity interests in other Guarantors, as applicable. Senior Secured Line of Credit On April 28, 2017, we terminated our senior secured line of credit under the Prior Credit Agreement. A portion of the proceeds of the initial loans under the Term Loan were used to refinance loans outstanding under the Prior Credit Agreement. In conjunction with the retirement of the Prior Credit Agreement, we expensed $3.4 million of associated unamortized debt issuance costs, included in Loss on Extinguishments of Debt Senior Notes On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Second Lien Notes 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 11, Income Taxes In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of 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. The Company has not made the semi-annual interest payment to the holders of our second lien notes that was due on April 2, 2018, and if such interest payment is not made prior to the expiration of the 30 day grace period, the maturity date of the second lien notes will be, upon requisite notice, subject to acceleration. This nonpayment of the semi-annual interest payment on the second lien notes is an event of default under the Company’s Term Loan, which upon requisite notice, would result in an acceleration of the Term Loan maturity date as well. 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 year ended December 31, 2017 of approximately $0.4 million, included as a component of Gain (Loss) on Extinguishments of Debt in our Consolidated Statements of Operations. We may redeem, at specified redemption prices, some or all of the Second 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. Our Existing Notes and Second Lien Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges on our Consolidated Balance Sheets. The Senior Notes are governed by indentures (the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00. As of December 31, 2017, our Fixed Charge Coverage Ratio was 1.10 to 1.00. We expect our Fixed Charge Coverage Ratio to be in compliance for the foreseeable future. As of December 31, 2017, we were limited to incurring approximately $161.7 million of additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual trustees under the Indentures or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. As of December 31, 2017 and December 31, 2016, we had recorded on our Consolidated Balance Sheets approximately $14.0 million and $3.6 million, respectively, of net premium/discounts related to the Senior Notes. The amortization of our net premium during the years ended December 31, 2017 and 2016, which follows the effective interest method, was approximately $10.4 million and $5.2 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year. Total interest expense for the year ended December 31, 2017 is comprised of non-cash amortization of $16.2 million, cash interest payments of $22.4 million and an increase in accrued interest of $10.2 million. Total interest expense for the year ended December 31, 2016 is comprised of non-cash amortization of $22.2 million, cash interest payments of $29.7 million and a decrease in accrued interest of $8.4 million. December 31, 2017 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 189,500 $ (4,711 ) $ (2,761 ) $ — $ 182,028 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ 20 $ (80 ) $ — $ 7,273 6.25% Senior Notes due 2022 5,363 — (67 ) — 5,296 1% / 8% Second Lien Senior Notes due 2020 587,606 (13,991 ) 33,751 30,436 637,802 $ 600,302 $ (13,971 ) $ 33,604 $ 30,436 $ 650,371 Other Long-Term Debt Long-Term Capital Leases - 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 (1,926 ) $ 8,156 December 31, 2016 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Senior Secured Line of Credit, Net Revolving Senior Credit Facility $ 117,670 $ — $ (3,885 ) $ — $ 113,785 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,573 $ 26 $ (107 ) $ — $ 7,492 6.25% Senior Notes due 2022 5,648 — (82 ) — 5,566 1% / 8% Second Lien Senior Notes due 2020 587,956 (3,627 ) 8,098 32,676 625,103 $ 601,177 $ (3,601 ) $ 7,909 $ 32,676 $ 638,161 Other Long-Term Debt Long-Term Capital Leases and Other Notes Payable- Equipment Financing Due March, 2021 $ 760 Due June, 2021 2,225 Due September, 2021 1,174 Total Capital Lease Obligations $ 4,159 Other Notes Payable 14 Total Capital Lease and Note Payable Obligations $ 4,173 Less: Current Portion of Capital Leases and Other Notes Payable (764 ) $ 3,409 The following is the principal maturity schedule for total debt outstanding as of December 31, 2017: ($ in thousands) 2018 (a) $ 791,728 2019 2,252 2020 2,636 2021 2,462 2022 806 Thereafter — Total (b) $ 799,884 a) Due to existing and anticipated covenant violations, the Company’s Term Loan and Senior Notes were classified as current at December 31, 2017. b) Does not include $18.7 million net unamortized premium/discount, $30.8 million of net unamortized debt issuance costs, and $30.4 million of unamortized deferred gain on debt restructurings. Covenant Violations The audit report the Company received with respect to its consolidated financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under the senior term loan facility. See “Going Concern” in Note 1 – Basis of Presentation and Principals of Consolidation for information regarding additional events of default that have occurred subsequent to December 31, 2017.

Fair Value Of Financial Instrum

Fair Value Of Financial Instruments And Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Fair Value Of Financial Instruments And Derivative Instruments	10. FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS Natural Gas, NGLs, and Oil Derivatives We enter derivative financial instruments with the primary objective of managing our exposure to commodity price fluctuations and providing more predictable cash flows. Our results of operations and operating cash flows are impacted by changes in market prices for natural gas, NGLs, and oil. To mitigate a portion of the exposure to adverse market changes, we enter into natural gas, NGLs, and oil 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 December 31, 2017, 2016 and 2015, 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 our Consolidated Statements of Operations. For additional information, see Note 2, Summary of Significant Accounting Policies Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established. Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing and between Henry Hub and Texas Gas pricing. We enter into the majority of our derivative arrangements with two counterparties and have a netting agreement in place with these counterparties, however the fair value of our derivative contracts are reported on a gross basis. 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, 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 Income (Expense). We paid net cash settlements of $10.1 million, in relation to our commodity derivatives for the year ended December 31, 2017, and we received net cash settlements of $32.6 million and $54.9 million in relation to our commodity derivatives for the years ended December 31, 2016 and 2015, respectively. Contingent Consideration – Sale of Illinois Basin Operations In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets, as defined in the contract, are achieved at specified future dates (see Note 4, Discontinued Operations/Assets Held for Sale Gain/Loss on Derivatives, Net Interest Rate Derivatives We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of December 31, 2017, we had approximately $189.5 million in borrowings outstanding under our Term Loan, which is subject to variable rates of interest, and had $600.3 million of Senior Notes outstanding subject to a fixed interest rate. See Note 9, Long-Term Debt We did enter into fixed-to-variable interest rate swaps during 2015, however there were no arrangements in place as of December 31, 2017 and 2016. We utilize the mark-to-market accounting method to account for our interest rate swaps. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense). During the year ended December 31, 2015, we received cash payments of approximately $0.9 million, related to our interest rate swaps. Derivative Instruments from Continuing Operations The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015: For the Year Ended December 31, ($ in Thousands) 2017 2016 2015 Oil $ (500 ) $ (1,515 ) $ 7,132 Natural Gas 13,889 (15,036 ) 37,647 NGLs (13,520 ) (17,788 ) 14,839 Interest Rate — — 934 Refined Products — 54 (376 ) Contingent Consideration (1,216 ) 1,770 — Gain (Loss) on Derivatives, Net $ (1,347 ) $ (32,515 ) $ 60,176 We account for our derivatives in accordance with ASC 815, which requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The fair value associated with our derivative instruments was a net liability of $19.4 million and $28.2 million at December 31, 2017 and 2016, respectively. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2017 consisted of the following: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2018 - Swaps 95,000 Bbls $ — $ — $ — $ 53.93 $ (518 ) 2018 - Collars 18,000 Bbls — 53.00 60.00 — (31 ) 2018 - Three-Way Collars 72,000 Bbls 42.29 51.46 61.38 — (92 ) 2019 - Swaps 31,500 Bbls — — — 51.00 (90 ) 2019 - Collars 60,250 Bbls — 45.00 55.07 — (100 ) 2019 - Three-Way Collars 50,250 Bbls 38.81 48.81 58.35 — (94 ) 2020 - Swaps 24,000 Bbls — — — 51.00 (90 ) 2020 - Collars 71,750 Bbls 45.00 55.10 (133 ) 2020 - Three-Way Collars 29,600 Bbls 39.24 49.24 56.99 — (52 ) 2021 - Swaps 6,000 Bbls — — — 51.00 (22 ) 2021 - Collars 63,750 Bbls — 45.00 55.02 — (123 ) 2021 - Three-Way Collars 24,000 Bbls 37.50 47.50 60.25 — (12 ) 2022 - Collars 36,000 Bbls — 45.00 54.75 — (69 ) 2022 - Three-Way Collars 6,000 Bbls 37.50 47.50 60.25 — (3 ) 588,100 Bbls $ (1,429 ) Natural Gas 2018 - Swaps 15,335,000 Mcf $ — $ — $ — $ 3.10 $ 3,733 2018 - Three-Way Collars 10,600,000 Mcf 2.33 2.90 3.52 — 1,672 2018 - Calls 5,810,000 Mcf — — 3.97 — (154 ) 2018 - Collars 4,415,000 Mcf — 2.66 3.10 — 37 2018 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.83 ) (3,604 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) 173 2019 - Swaps 10,470,000 Mcf — — — 2.84 154 2019 - Three-Way Collars 8,205,000 Mcf 2.27 2.77 3.40 — 132 2019 - Collars 7,520,500 Mcf — 2.54 3.04 — (295 ) 2019 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.84 ) (3,570 ) 2020 - Swaps 4,560,000 Mcf — — — 2.87 13 2020 - Three-Way Collars 4,555,000 Mcf 2.23 2.73 3.30 — 113 2020 - Collars 4,720,000 Mcf — 2.51 3.05 — (183 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.84 ) (1,945 ) 2021 - Swaps 3,875,000 Mcf — — — 2.77 (87 ) 2021 - Three-Way Collars 3,037,500 Mcf 2.17 2.67 3.15 — (30 ) 2021 - Collars 2,737,500 Mcf — 2.50 3.05 — (134 ) 2021 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 2022 - Swaps 2,730,000 Mcf — — — 2.73 (91 ) 2022 - Three-Way Collars 2,047,500 Mcf 2.15 2.65 3.10 — (58 ) 2022 - Collars 2,047,500 Mcf — 2.50 3.05 — (101 ) 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 154,735,500 Mcf $ (5,829 ) NGLs 2018 - C3+ NGL Swaps 1,367,572 Bbls $ — $ — $ — $ 33.30 $ (10,254 ) 2018 - Ethane Swaps 1,247,500 Bbls — — — 12.92 900 2019 - C3+ NGL Swaps 705,922 Bbls — — — 30.65 (2,750 ) 2019 - C5 Collars 113,040 Bbls — 45.00 54.83 — (308 ) 2019 - Ethane Swaps 727,500 Bbls — — — 12.98 306 2019 - C5 Three-Way Collars 8,472 Bbls — 32.31 50.00 55.75 (17 ) 2020 - C3+ NGL Swaps 271,276 Bbls — — — 37.63 (1,157 ) 2020 - C5 Collars 28,260 Bbls — 45.00 54.83 — (77 ) 2020 - Ethane Swaps 448,500 Bbls — — — 12.83 (9 ) 2020 - C5 Three-Way Collars 28,134 Bbls — 32.31 50.00 55.75 (49 ) 2021 - C3+ NGL Swap 158,112 Bbls — — — 45.62 (376 ) 2021 - Ethane Swaps 251,000 Bbls — — — 12.77 (3 ) 2022 - C3+ NGL Swap 48,984 Bbls — — — 50.56 (74 ) 2022 - Ethane Swaps 111,500 Bbls — — — 12.69 (9 ) 5,515,772 Bbls $ (13,877 ) The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016 is summarized below. December 31, December 31, ($ in Thousands) 2017 2016 Short-Term Derivative Assets: NGL—Swaps 928 — Natural Gas—Swaps 3,734 206 Natural Gas—Cap Swaps — 61 Natural Gas—Collars 183 — Natural Gas—Basis Swaps 191 232 Natural Gas—Three-Way Collars 1,721 151 Contingent Consideration - Sale of Illinois Basin 1,251 1,223 Total Short-Term Derivative Assets $ 8,008 $ 1,873 Long-Term Derivative Assets: NGL—Swaps 409 — Natural Gas—Swaps 411 206 Natural Gas—Basis Swaps — 293 Natural Gas—Three-Way Collars 429 — Contingent Consideration - Sale of Illinois Basin 470 1,713 Total Long-Term Derivative Assets $ 1,719 $ 2,212 Total Derivative Assets $ 9,727 $ 4,085 Short-Term Derivative Liabilities: Crude Oil—Collars $ (31 ) $ (86 ) Crude Oil—Deferred Put Spread — (9 ) Crude Oil—Three-Way Collars (92 ) (132 ) Crude Oil—Swaps (518 ) (220 ) NGL—Swaps (10,281 ) (9,895 ) Natural Gas—Three-Way Collars (49 ) (2,397 ) Natural Gas—Cap Swaps — (3,364 ) Natural Gas—Collars (146 ) (873 ) Natural Gas—Basis Swaps (3,621 ) (640 ) Natural Gas—Call (154 ) (1,478 ) Natural Gas—Swaption — (1,258 ) Natural Gas—Swaps — (4,673 ) Total Short - Term Derivative Liabilities $ (14,892 ) $ (25,025 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars $ (161 ) $ (58 ) Crude Oil—Swaps (202 ) (146 ) Crude Oil—Collars (425 ) — NGL—Swaps (4,482 ) (2,200 ) NGL—Collars (385 ) — NGL—Three Way Collars (66 ) — Natural Gas—Swaps (423 ) (1,004 ) Natural Gas—Swaption — (167 ) Natural Gas—Basis Swaps (7,120 ) (1,260 ) Natural Gas—Collars (713 ) (115 ) Natural Gas—Call — (491 ) Natural Gas—Three-Way Collars (272 ) (1,786 ) Total Long-Term Derivative Liabilities $ (14,249 ) $ (7,227 ) Total Derivative Liabilities $ (29,141 ) $ (32,252 ) Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of December 31, 2017 and 2016, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. We had no Level 3 commodity derivative contracts outstanding as of December 31, 2017 and 2016. The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the years ended December 31, 2017 and 2016, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at December 31, 2017 Using: ($ 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 ) $ — Fair Value Measurements at December 31, 2016 Using: ($ in Thousands) Total Carrying Value as of December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (28,167 ) $ — $ (28,167 ) $ — Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations. The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of December 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, swaption, three way collar, basis swap, cap swap, call and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of December 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of December 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments. The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2017 and 2016 (in thousands): For the Year Ended December 31, ($ in Thousands) 2017 2016 Beginning Balance of Level 3 $ — $ (5,506 ) Changes in Fair Value — 7,249 Transfers out of Level 3 — (1,564 ) Purchases — — Settlements Received — (179 ) Ending Balance of Level 3 $ — $ — Changes in fair value on our Level 3 commodity derivative contracts outstanding for the years ended December 31, 2017 and 2016, resulted in no change and an increase of approximately $7.2 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. Asset Retirement Obligations We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: December 31, 2017 December 31, 2016 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 650,371 $ 265,438 $ 638,161 $ 147,605 Secured Lines of Credit 182,028 182,028 113,785 113,785 Capital Leases and Other Obligations 10,082 7,138 4,173 3,234 Total $ 842,481 $ 454,604 $ 756,119 $ 264,624 The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy. 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 years ended December 31, 2017 and 2016, we recorded impairments of $21.4 million and $74.6 million, respectively, related to proven and unproved properties. We primarily use proved reserve reports in our determination of impairment. 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 calculation are considered to be Level 3 within the fair value hierarchy. For additional information on our impairment, see Note 16, Impairment Expense

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	11. INCOME TAXES We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax basis of assets and liabilities using enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Our income tax expense from continuing operations consisted of the following: For the Years Ended December 31, ($ in Thousands) 2017 2016 2015 Current: Federal $ (2,001 ) $ 1,839 $ — State (597 ) 597 - Deferred: Federal (130 ) — 5,773 State — — 257 Income Tax (Benefit) Expense $ (2,728 ) $ 2,436 $ 6,030 A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows: ($ in Thousands) Year Ended December 31, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 Income (Loss) from continuing operations before noncontrolling interests and income taxes $ (66,970 ) $ (195,201 ) $ (346,752 ) Statutory U.S. income tax rate 35.0 % 35.0 % 35.0 % Tax expense recognized using statutory U.S. income tax rate $ (23,440 ) $ (68,320 ) $ (121,363 ) State income taxes, net of federal income tax benefit (1,723 ) (3,632 ) (17,137 ) Change in future rates 79,322 (400 ) (212 ) Permanent differences 1,130 2,264 1,784 Change in valuation allowances (57,622 ) 72,784 143,566 Other (395 ) (260 ) (608 ) Total income tax expense $ (2,728 ) $ 2,436 $ 6,030 Effective income tax rate 4.07 % -1.25 % -1.74 % The current tax benefit of $2.6 million is the result of reconciling the 2016 tax returns to the expected Federal and State liabilities generated by the CODI incurred in 2016. Of the current benefit $2.0 million is related to AMT and $0.6 million is related to state tax. The $0.1 million of deferred tax benefit is related to the removal of the valuation allowance associated with the Alternative Minimum Tax Credit Carry-forward as described in the Tax Law Changes paragraph below. Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2017 and 2016: For the Years Ended December 31, ($ in Thousands) 2017 2016 Tax effects of temporary differences for: Assets: Asset retirement obligation $ 2,647 $ 3,955 Deferred compensation plans 600 1,581 Compensation Accruals 390 762 Unrealized loss on derivatives 5,457 11,760 Net operating loss carryforwards 126,820 79,531 Deferred Financing Costs (a) 98,065 182,519 Gas Transportation Capacity Commitments 1,697 3,031 Deferred revenue timing differences 388 443 Organization costs 213 391 Percentage depletion carryforward 2,155 2,717 AMT credits 130 2,131 Timing differences - tax partnerships 465 1,046 Other 217 331 Valuation allowances (154,416 ) (212,041 ) Total Deferred Tax Assets net of Valuation Allowances $ 84,828 $ 78,157 Liabilities: Book basis of oil and gas properties in excess of tax basis (84,622 ) (77,690 ) Other (76 ) (467 ) Total Deferred Tax Liabilities $ (84,698 ) $ (78,157 ) Net Deferred Tax Asset $ 130 $ — (a) Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016. Tax Law Changes – Tax Effects The Tax Cuts and Jobs Act (H.R. 1) was enacted on December 22, 2017. The new law reduces the federal corporate tax rate to 21% from 35% for tax years ending after December 31, 2017. The rate change led to a $79.3 million reduction in our net deferred tax asset but did not result in any deferred expense due the offsetting valuation allowance. The law also provides for a refund of the Alternative Minimum Tax Credit over four years beginning in 2018, allowing for the removal of the valuation allowance associated with this deferred tax attribute. Although we do not expect any immediate negative impacts from the passage of H.R. 1, the law does limit the interest deduction while also limiting the NOL deduction to 80% of taxable income. Both of these limitations could lead to current tax expense in a future period. The extent to which state tax authorities pass legislation to conform with or decouple from the Federal legislation could also have positive or negative impacts on our tax burden in future periods. Debt Exchanges – Tax Effects During 2016, we completed a series of debt for equity exchanges with holders of our Senior Notes. We accounted for the exchanges as troubled debt restructurings. For additional information regarding the exchanges, see Note 9, Long-Term Debt . Effective January 1, 2016 Management elected to early adopt ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting Summary of Significant Accounting Policies Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize our inventory of deferred tax assets. The company’s deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2017, management determined, based on positive and negative evidence, including our three-year cumulative loss position that it was necessary to provide a valuation allowance of approximately $154.4 million for deferred tax assets for which the company may be unable to realize the tax benefit. For the year ended December 31, 2016, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it was necessary to provide a valuation allowance of approximately $212.0 million for deferred tax assets for which the company may be unable to realize the tax benefit. Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances. At December 31, 2017, we had available unused gross federal net operating loss carryforwards of $407.6 million and gross state net operating loss carryforwards of $533.9 million that may be applied against future taxable income that expire from 2023 through 2037. The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected): Year of Expiration Net Operating Loss Carryforwards (in thousands) 2023 2 2024 — 2025 — 2026 572 2027 1,183 2028 35 2029 18 2030 95 2031 2,089 2032 36 2033 2,227 2034 2,730 2035 39,280 2036 15,236 2037 63,317 Total 126,820 Due to a change of ownership, as defined under the provisions of the Tax Reform Act of 1986, which occurred during 2016, a portion of our domestic net operating loss and tax credit carryforwards may be limited in future periods. Internal Revenue Code Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event. As a result of this ownership change, certain of our accumulated net operating losses may be subject to an annual limitation regarding their utilization against taxable income in future periods. The 2016 change creates an estimated annual utilization limit of approximately $1.4 million on our ability to utilize net operating losses generated prior to the ownership change event. Built-in gains associated with our deferred tax attributes on the date of the ownership change may decrease the net operating loss utilization limit in future periods, allowing additional utilization of net operating losses generated prior to the date of the ownership change. FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position. Our management has concluded that, as of December 31, 2017, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no-liability balance is required to offset any unsustainable positions. We did not have any accrued interest or penalties as of December 31, 2017 and 2016. We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States federal jurisdiction and in many state jurisdictions. We are subject to U.S. federal income tax examinations and to various state tax examinations for periods after December 31, 2012.

Earnings Per Common Share

Earnings Per Common Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Common Share	12. 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 year ended December 31, 2017, we excluded stock options to purchase 0.1 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2016 and 2015, we excluded stock options to purchase 1.2 million shares and 0.4 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2017, 2016 and 2015, we excluded performance-based restricted stock of 0.1 million shares, 0.6 million shares and 1.1 million shares, respectively, due to our Net Loss from Continuing Operations (for additional information on our non-cash compensation plans, see Note 15, Employee Benefit and Equity Plans Year Ended December 31, Year Ended December 31, Year Ended December 31, (in thousands, except per share amounts) 2017 2016 2015 Numerator: Net Loss From Continuing Operations $ (64,242 ) $ (197,637 ) $ (352,782 ) Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests — 20,922 (10,496 ) Less: Preferred Stock Dividends (2,392 ) (5,091 ) (9,660 ) Effect of Preferred Stock Conversions — 72,984 — Net Loss Attributable to Common Shareholders $ (66,634 ) $ (108,822 ) $ (372,938 ) Denominator: Weighted Average Common Shares Outstanding - Basic 9,902 7,926 5,439 Effect of Dilutive Securities: Employee Stock Options — — — Employee Performance-Based Restricted Stock Awards — — — Effect of Assumed Conversions of Preferred Stock — — — Weighted Average Common Shares Outstanding - Diluted 9,902 7,926 5,439 Earnings per Common Share Attributable to Rex Energy Common Shareholders(a): Basic — Net Loss From Continuing Operations $ (6.73 ) $ (16.37 ) $ (66.64 ) — Net Income (Loss) From Discontinued Operations — 2.64 (1.93 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (6.73 ) $ (13.73 ) $ (68.57 ) Diluted — Net Loss From Continuing Operations $ (6.73 ) $ (16.37 ) $ (66.64 ) — Net Income (Loss) From Discontinued Operations — 2.64 (1.93 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (6.73 ) $ (13.73 ) $ (68.57 ) (a) All earnings per share amounts are attributable to Rex common shareholders.

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Capital Stock	13. CAPITAL STOCK Reverse Stock Split As discussed in Note 1, Basis of Presentation and Principles of Consolidation Common Stock Our common stock previously traded on The Nasdaq Capital Market under the symbol “REXX”. On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department of 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 requested an appeal before the Nasdaq Hearings Panel. We did not appeal this determination and the time period in which to appeal has lapsed. Following the delisting of our common stock from Nasdaq, our common stock may be eligible for quotation on the OTCBB or OTC Markets Group’s Pink marketplace. Trading on the OTCBB or Pink marketplace may occur only if a market maker applies to quote our common stock and we are current in our reporting obligations under the Securities Exchange Act of 1934. Once our common stock is delisted from Nasdaq, there can be no assurance that a market maker will apply to quote our common stock or that our common stock then will be eligible for quotation on the OTCBB or the Pink marketplace. On May 27, 2016, our common shareholders approved an increase in the number of authorized shares from 100,000,000 to 200,000,000 common shares. On May 5, 2017, 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. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of December 31, 2017 and 2016, we had 10,244,394 and 9,787,146 shares of common stock outstanding, respectively. During the year ended December 31, 2017, we issued approximately 0.3 million shares of our common stock as payment of our preferred stock dividend and 0.1 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes. During the year ended December 31, 2016, we issued approximately 0.8 million shares of our common stock in conjunction with the Exchange completed on March 31, 2016, and approximately 2.4 million shares of our common stock in debt-to-equity exchanges with certain holders of our Senior Notes. See Note 9, Long-Term Debt Preferred Stock As of December 31, 2017 and 2016, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), issued and outstanding totaled 3,987 for each period, respectively. During the year ended December 31, 2016, 12,113 shares of Series A Preferred Stock were converted into an aggregate of approximately 0.9 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. See Note 12, Earnings Per Common Share 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 each 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. For the year ended December 31, 2017, we paid cash dividends of $150.00 per share in the aggregate amount of $1.2 million, for the periods of November 15, 2015 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 December 31, 2017, accumulated dividends in arrears totaled approximately $3.0 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulated dividends are added to our Net Loss in the determination of Loss Attributable to Common Shareholders and related loss per share calculations. No dividends were declared by our board of directors in 2016. For the year ended December 31, 2015, we declared quarterly cash dividends totaling approximately $9.7 million. The Series A Preferred Stock is convertible at the option of the holder at an initial conversion rate of 55.56 shares of our common stock per share (0.5556 shares of our common stock per depositary share), equivalent to an initial conversion price of $18.00 per share of common stock. The conversion price represents a premium of approximately 25.2% relative to the Nasdaq Global Market closing sale price of our common stock on August 12, 2014, or $14.38 per share. At any time on or after August 30, 2019, we may at our option cause all outstanding shares of the Series A Preferred Stock to be automatically converted into common stock at the then-applicable conversion price, if the closing sale price of our common stock exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series A Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to the converting holder. If we do not pay dividends for an aggregate of six quarterly periods, the holders of the Series A Preferred Stock will have the right to elect two additional directors to our board of directors.

Major Customers

Major Customers	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Major Customers	14. MAJOR CUSTOMERS For the year ended December 31, 2017, approximately $143.8 million, or 78.5%, of our commodity sales from continuing operations were attributable to three customers with the largest single purchaser accounting for $86.1 million, or 47.0%. For the year ended December 31, 2016, approximately $95.1 million, or 78.8%, of our commodity sales from continuing operations were attributable to three customers with the largest single purchaser accounting for $55.1 million, or 45.6%. For the year ended December 31, 2015, approximately $120.0 million, or 82.2%, of our commodity sales from continuing operations were derived from three customers, with the largest customer being responsible for approximately $76.0 million, or 52.0%, of total commodity sales.

Employee Benefit and Equity Pla

Employee Benefit and Equity Plans	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefit and Equity Plans	15. EMPLOYEE BENEFIT AND EQUITY PLANS 401(k) Plan We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Company matching contributions were suspended during 2016, and partially reinstated in October 2017. Our contributions to the plan attributable to continuing operations were negligible for the years ended December 31, 2017 and 2016 and were approximately $0.5 million for the year ended December 31, 2015. Equity Plans We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as a financing cash flow, rather than as an operating cash flow. 2007 Long-Term Incentive Plan We have granted stock options and restricted stock awards to various employees, non-employee directors and non-employee contractors under the terms of our Amended and Restated 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees may be designed, at the Compensation Committee’s discretion, to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes. The Compensation Committee has authorized the issuance of 597,947 shares under the Plan, with 217,552 and 238,579 still available as of December 31, 2017 and 2016, respectively. All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with between five and ten year expiration at an exercise price equal to our closing price on the Nasdaq Global Select Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively. Stock Options Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan. During the year ended December 31, 2017, there were no issuances of options to purchase shares of our common stock. During the year ended December 31, 2016, we issued 88,892 options to purchase shares of our common stock to 34 employees. A summary of the stock option activity is as follows: Number of Shares Weighted-Average Exercise Price Weighted-Average Remaining Term (in years) Aggregate Intrinsic Value (in thousands) Options outstanding December 31, 2014 40,268 $ 108.20 Granted 8,000 44.80 Exercised — — Cancelled/Forfeited (3,889 ) 112.30 Options outstanding December 31, 2015 44,379 $ 96.40 Granted 88,892 16.60 Exercised — — Cancelled/Forfeited (15,149 ) 57.20 Options Outstanding December 31, 2016 118,122 $ 41.40 Granted — — Exercised — — Cancelled/Forfeited (31,791 ) 72.60 Options Outstanding December 31, 2017 86,331 $ 29.90 4.7 $ — Options Exercisable December 31, 2017 32,746 $ 45.30 4.2 $ — Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2017 and 2016 was $0.4 million and $0.4 million, respectively. Expense related to stock-based compensation relating to stock options for the year ended December 31, 2015 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative expense. No stock options were exercised for the years ended December 31, 2017, 2016 and 2015. The total tax benefit for the years ended December 31, 2017, 2016 and 2015was negligible. We use the Black-Scholes option pricing model to calculate the fair value of stock option awards. Determining the fair value of equity-based awards requires judgement, including estimating the expected term that options will be outstanding prior to exercise, and the associated volatility measure. The fair value of each option award is estimated on the date of the grant. The assumptions used to estimate the fair value of options granted during the years ended December 31, 2017 and 2016 are as follows: Year Ended December 31, 2017 2016 Expected dividend yield 0% 0% Expected stock price volatility 87.8% - 96.5% 87.8% - 96.5% Risk-free interest rate 1.1% - 1.5% 1.1% - 1.5% Expected life of options (years) 4 - 5 4 - 5 A summary of the status of our issued and outstanding stock options as of December 31, 2017 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 12/31/17 Weighted-Average Exercise Price Number Exercisable At 12/31/17 Weighted-Average Exercise Price $ 9.70 2,750 $ 9.70 919 $ 9.70 $ 16.90 67,294 $ 16.90 22,873 $ 16.90 $ 40.50 4,000 $ 40.50 — $ — $ 49.00 4,000 $ 49.00 667 $ 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 86,331 $ 29.90 32,746 $ 45.30 The weighted average remaining contractual term for options exercisable at December 31, 2017 was 4.2 years and the aggregate intrinsic value was negligible. The weighted average remaining contractual term for options exercisable at December 31, 2016 were 1.2 years and the aggregate intrinsic value was negligible. As of December 31, 2017, unrecognized compensation expense related to stock options was $0.1 million. Restricted Stock Awards During the year ended December 31, 2017, the Compensation Committee issued 101,237 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. During the year ended December 31, 2016, the Compensation Committee issued 142,309 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2017 and 2016 are subject to time vesting and, in some cases, performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date until the date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted common stock is valued at the closing price of our common stock on the Nasdaq Global Select Market or the Nasdaq Capital Market, as applicable, on the date of the grant. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse for performance-based awards to varying degrees based on performance metrics at the time of the change in control. For awards that do not contain a performance-based condition, all restrictions immediately lapse upon a change in control. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period. Certain of the restricted common stock awards 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 of 13 to 15 companies over a three-year period. The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule: TSR Rank Percentage of Awards to Vest 1-3 100 % 4-6 75 % 7-10 50 % 11-13 25 % 14-16 0 % The weighted average fair value of the TSR awards as of December 31, 2015 were $2.56. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions: Year Ended December 31, 2015 Expected Dividend Yield 0.0 % Risk-Free Interest Rate 1.0 % Expected Volatility – Rex Energy 58.6 % Expected Volatility – Peer Group 29.8%-85.0% Market Index 35.6 % Expected Life Three Years The dividend yield of zero reflects the fact that we have never paid cash dividends on our common stock and have no present intentions of doing so. The risk-free interest rate reflects the U.S. Treasury Constant Maturity rates as of the measurement date, converted into an implied “spot rate” yield. Our expected volatility estimates are based on observed historical volatility of daily stock returns for the three-year period preceding the grant date. Market index is an equal-weight index of the companies in the peer group. Expected life is measured as the grant date through the end of the performance period. Performance and market shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Compensation expense for the TSR awards is recognized on a straight-line basis over the vesting period. Stock-based compensation expense from continuing operations related to restricted common stock awards for the years ended December 31, 2017, 2016 and 2015 was $0.9 million, $2.7 million and $5.8 million, respectively. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of approximately 18,987 restricted stock awards with associated expense of approximately $2.5 million. As of December 31, 2017, total unrecognized compensation cost related to the restricted common stock grants was approximately $0.6 million to be recognized over a weighted average of 1.4 years. The total fair value of restricted common stock awards that vested in 2017 was approximately $0.4 million as compared to $0.6 million for restricted common stock awards that vested in 2016. A summary of the restricted stock activity for the years ended December 31, 2017, 2016 and 2015 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2014 152,005 $ 140.50 Awards 223,684 33.50 Vested (60,636 ) 93.90 Forfeitures (67,037 ) 113.30 Restricted stock awards, as of December 31, 2015 248,016 $ 62.70 Awards 142,309 9.10 Vested (87,206 ) 73.30 Forfeitures (60,295 ) 67.30 Restricted stock awards, as of December 31, 2016 242,824 $ 26.30 Awards 101,237 5.18 Vested (102,351 ) 21.52 Forfeitures (41,235 ) 48.17 Restricted stock awards, as of December 31, 2017 200,475 $ 13.62

Impairment Expense

Impairment Expense	12 Months Ended
	Dec. 31, 2017
Impairment Of Oil And Gas Properties [Abstract]
Impairment Expense	16. IMPAIRMENT EXPENSE For the years ended December 31, 2017, 2016 and 2015, we incurred impairment expense from continuing operations of approximately $21.4 million, $74.6 million and $283.2 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 (for additional information see Note 2, Summary of Significant Accounting Policies During 2016, we recorded impairment expense from continuing operations of $74.6 million. Approximately $28.3 million of the impairment incurred during 2016 was attributable to unconventional proved properties in the Appalachian Basin. In addition, we also incurred approximately $46.3 million in unproved property impairments for leases that expired or are expected to expire without being developed in Butler County, Pennsylvania and Ohio. During 2015, we recorded impairment expense from continuing operations of $283.2 million. Approximately $223.6 million of the impairment incurred during 2015 was attributable to proven properties and other fixed assets, of which approximately $204.6 million was attributable to unconventional assets in the Appalachian Basin and $17.5 million was attributable to our equity method investment in RW Gathering. The remaining proved property impairment expense is related to our conventional dry gas assets and salt water disposal well in the Appalachian Basin. In addition, we also incurred approximately $59.6 million in unproved property impairments related to leases in the Appalachian Basin that will not be developed.

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Suspended Exploratory Well Costs	17. SUSPENDED EXPLORATORY WELL COSTS We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for each of the years ended December 31, 2017, 2016 and 2015 ($ in thousands): 2017 2016 2015 Beginning Balance at January 1, $ 17,201 $ 16,970 $ 22,573 Additions to capitalized exploratory well costs pending the determination of estimated proved reserves 91,166 46,759 144,333 Divested wells (31 ) — — Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves (107,883 ) (39,126 ) (147,054 ) Capitalized exploratory well costs charged to expense — (7,402 ) (2,882 ) Ending Balance at December 31, 453 17,201 16,970 Less exploratory well costs that have been capitalized for a period of one year or less (453 ) (17,201 ) (12,049 ) Capitalized exploratory well costs for a period of greater than one year $ — $ — $ 4,921 Number of projects that have exploratory well costs capitalized for a period of more than one year — — 13 As of December 31, 2017 and 2016, there were no capitalized exploratory well costs that were capitalized for a period greater than one year. The costs as of December 31, 2015 were related to 13 properties located in Pennsylvania for wells that we purchased through our acquisition from Shell in 2014. Due to the required development timing of these properties combined with our current development plan and optimization of our capital spend, we did not allocate capital to complete the wells or build out the infrastructure to place them into sales and these costs were reclassified to Impairment Expense.

Costs Incurred In Oil And Natur

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities	18. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (UNAUDITED) Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands): 2017 2016 2015 Consolidated Entities: Acquisition of Properties Proved $ — $ — $ — Unproved 3,805 6,671 27,933 Exploration Costs(a) 90,700 24,650 157,067 Development Costs(a) 45,983 11,166 17,336 Subtotal 140,488 42,487 202,336 Asset Retirement Obligations 797 1,927 2,739 Total Costs Incurred $ 141,285 $ 44,414 $ 205,075 Share of Equity Method Investments: Acquisition of Properties Proved $ — $ — $ — Unproved — — — Exploration Costs — — — Development Costs(a) 800 793 824 Total $ 800 $ 793 $ 824 (a) Includes Depreciation expense for support equipment and facilities The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands): 2017 2016 2015 Total Costs Incurred by Consolidated Entities $ 141,285 $ 44,414 $ 205,075 Illinois Basin Expenditures — — 15,405 Exploration Expense (527 ) (2,178 ) (2,617 ) Asset Retirement Obligations (797 ) (1,927 ) (2,739 ) Depreciation for Support Equipment and Facilities (2,170 ) — (4,905 ) Corporate Expenditures 416 — 231 Other (a) 87 — (16,522 ) Total Capital Expenditures $ 138,294 $ 40,309 $ 193,928 (a) Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and BSP and intercompany capital transactions.

Oil And Natural Gas Capitalized

Oil And Natural Gas Capitalized Costs	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Oil And Natural Gas Capitalized Costs	19. OIL AND NATURAL GAS CAPITALIZED COSTS (UNAUDITED) Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands): 2017 2016 Consolidated Entities: Proven Oil and Natural Gas Properties $ 1,086,625 $ 1,055,467 Pipelines and Support Equipment 18,902 21,088 Field Operation Vehicles and Other Equipment 9,586 11,239 Wells and Facilities in Progress 38,660 21,964 Unproven Properties 186,523 215,794 Total 1,340,296 1,325,552 Less Accumulated Depreciation and Depletion (459,652 ) (474,046 ) Total $ 880,644 $ 851,506 Share of Equity Method Investments: Pipelines and Support Equipment 19,963 19,962 Wells and Facilities in Progress — — Total 19,963 19,962 Less Accumulated Depreciation and Depletion (5,011 ) (4,211 ) Total $ 14,952 $ 15,751

Oil and Natural Gas Reserve Qua

Oil and Natural Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Oil and Natural Gas Reserve Quantities	20. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED) Our independent engineers, NSAI evaluated all of our proved oil, natural gas and NGL reserves for the years ended December 31, 2017, 2016 and 2015. The technical persons responsible for preparing the estimates of our estimated proved reserves meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil, natural gas and NGL reserve estimates were generally based upon extrapolation of historical production trends, performance analysis, and analogy to similar properties. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our estimated proved reserves are located within the United States. Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Developed natural gas, oil and NGL reserves are reserves of any category that can be expected to be recovered (x) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (y) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped natural gas, oil and NGL reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty. Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2017, 2016 and 2015. We accounted for the estimated proved reserves of our Illinois Basin assets as a sale in 2016. Prior years were not retroactively adjusted for the effect of discontinued operations. 2017 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 1,866.0 44,824.4 367,640.9 647,783.1 Extensions, Discoveries and Additions 1,929.6 22,295.2 164,222.7 309,571.7 Revisions of Previous Estimates 90.0 10,225.7 103,278.3 165,172.5 Sales of Reserves (144.5 ) (984.4 ) (14,790.4 ) (21,563.8 ) Production (271.8 ) (4,079.1 ) (41,972.0 ) (68,077.4 ) Estimated Proved Reserves-End of Period 3,469.3 72,281.8 578,379.5 1,032,886.1 2016 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 5,317.1 40,346.6 406,462.8 680,445.0 Extensions, Discoveries and Additions 373.5 2,183.7 11,084.6 26,427.8 Revisions of Previous Estimates 323.9 8,262.0 7,629.3 59,144.7 Sales of Reserves (3,788.1 ) (1,860.5 ) (12,917.7 ) (46,809.5 ) Production (360.4 ) (4,107.4 ) (44,618.1 ) (71,424.9 ) Estimated Proved Reserves-End of Period 1,866.0 44,824.4 367,640.9 647,783.1 2015 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 Extensions, Discoveries and Additions 949.0 10,079.3 76,816.9 142,986.7 Revisions of Previous Estimates (4,176.8 ) (38,249.7 ) (448,461.3 ) (703,020.3 ) Purchases (7.7 ) (1,389.6 ) (16,471.1 ) (24,854.9 ) Production (1,132.1 ) (3,345.9 ) (44,606.8 ) (71,474.8 ) Estimated Proved Reserves-End of Period 5,317.1 40,346.6 406,462.8 680,445.0 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Proved Developed Reserves December 31, 2017 2,235.4 64,738.5 519,118.6 920,962.0 December 31, 2016 1,865.9 44,824.4 367,641.3 647,783.1 December 31, 2015 4,944.6 37,941.9 389,754.4 647,073.4 Proved Undeveloped Reserves December 31, 2017 1,233.9 7,543.3 59,260.9 111,923.9 December 31, 2016 - - - - December 31, 2015 372.5 2,404.7 16,708.4 33,371.6 Our estimated proved undeveloped reserves did not include any locations that generated a positive future net revenue and a negative present value discounted at 10%. We may, from time to time, have proved undeveloped locations with these characteristics based on our planned operating budget and strategy to hold acreage by production combined with our expectations of future commodity prices. Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from developmental drilling and production history or resulting from a change in economic factors, such as commodity prices and operating costs. Our revisions in 2017 included a positive adjustment of approximately 165.0 Bcfe related primarily to positive well performance in our Butler, Moraine East, and Warrior North assets as well as an improvement in commodity prices as compared to 2016. Our revisions in 2016 included a positive adjustment of approximately 59.1 Bcfe related primarily to positive well performance in our Warrior North prospect in Ohio and increased ethane recovery expectations. Our revisions in 2015 included a negative adjustment of approximately 741.1 Bcfe related to lower commodity prices. This negative adjustment was partially offset by positive revision of approximately 15.4 Bcfe related to positive operating expenses, 4.1 Bcfe related to changes in our ethane recovery expectations and 18.6 Bcfe related to technical revisions. The positive technical revisions included 10.3 Bcfe in our Butler County, Pennsylvania area related to positive well performance. An additional 9.8 Bcfe of positive technical revisions were related to positive well performance in our Warrior North prospect in Ohio. These additions were partially offset by approximately 2.2 Bcfe in negative technical revisions related to well performance in our other areas of operation. Extensions, discoveries and other additions. These are additions to estimated proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with estimated proved reserves or of new reservoirs of estimated proved reserves in old fields. We had extensions, discoveries and other additions for the year ended December 31, 2017, of 1.9 MMBOE of oil, 22.3 MMBOE of NGLs and 164.0 Bcfe of natural gas. We had extensions, discoveries and other additions for the year ended December 31, 2016, of 0.4 MMBOE of oil, 2.2 MMBOE of NGLs and 11.1 Bcfe of natural gas. We had significant extensions, discoveries and other additions for the year ended December 31, 2015 of 0.9 MMBOE of oil, 10.1 MMBOE of NGLs and 76.8 Bcfe of natural gas. Our continued success in the Appalachian Basin has been the primary contributor to the growth of our extensions, discoveries and other additions, specifically the Marcellus and Utica Shales. At December 31, 2017, 100.0% of our extensions, discoveries and other additions were related to Marcellus Shale and Utica Shale properties.

Standardized Measure Of Discoun

Standardized Measure Of Discounted Future Net Cash Flows	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Standardized Measure Of Discounted Future Net Cash Flows	2 1. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of estimated proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process. The following summary sets forth our future net cash flows relating to proven oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2017, 2016 and 2015 ($ in thousands): 2017 2016 2015 Future Cash Inflows $ 2,952,274 (a) $ 1,371,210 (b) $ 1,716,131 (c) Future Costs: Production (1,721,109 ) (1,061,275 ) (1,144,049 ) Abandonment (9,866 ) (47,159 ) (143,459 ) Development (45,365 ) — (18,952 ) Net Future Cash Inflow Before Income Taxes 1,175,934 262,776 409,671 Future Income Tax Expense (24,105 ) — — Total Future Net Cash Flows Before 10.0% Discount 1,151,829 262,776 409,671 Less: Effect of 10.0% Discount Factor (644,810 ) (97,179 ) (154,048 ) Standardized Measure of Discounted Future Net Cash Flows $ 507,019 $ 165,597 $ 255,623 (a) Calculated using weighted average prices of $2.793 per Mcf, $45.62 per barrel of oil and $16.31 per barrel of NGLs (b) Calculated using weighted average prices of $2.264 per Mcf, $36.68 per barrel of oil and $10.50 per barrel of NGLs (c) Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs The principal sources of change in the standardized measure of discounted future net cash flows are as follows: 2017 2016 2015 Standardized Measure – Beginning of Period $ 165,597 $ 255,623 $ 1,025,364 Revisions of Previous Estimates: Changes in Prices and Production Costs 137,000 (89,583 ) (1,296,866 ) Revisions in Quantities 78,276 9,851 (270,673 ) Changes in Future Development Costs (41,803 ) 7,786 595,547 Accretion of Discount and Timing of Future Cash Flows 16,560 25,562 116,514 Net Change in Income Tax (24,105 ) — 139,776 Purchase (Sale) of Reserves in Place (6,692 ) (54,598 ) (37,101 ) Plus Extensions, Discoveries, and Other Additions 166,867 21,841 88,152 Development Costs Incurred 45,983 11,166 31,574 Sales of Product – Net of Production Costs (84,452 ) (34,301 ) (52,952 ) Changes in Timing and Other 53,788 12,250 (83,712 ) Standardized Measure – End of Period $ 507,019 $ 165,597 $ 255,623

Results Of Operations For Oil A

Results Of Operations For Oil And Gas Producing Activities	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Results of Operations for Oil and Gas Producing Activities	22. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation): 2017 2016 2015 Consolidated Entities (in thousands): Revenues Oil and Natural Gas Sales $ 205,266 $ 139,017 $ 138,749 Expenses Production and Lease Operating Expense 120,794 104,699 93,892 Impairment Expense 21,383 74,619 283,244 Exploration Expense 527 2,178 2,617 Depletion, Depreciation, Amortization and Accretion 59,028 62,874 85,844 Total Costs 201,732 244,370 465,597 Pre-Tax Operating Income (Loss) 3,534 (105,353 ) (326,848 ) Income Tax Benefit (Expense) (a) 144 (1,317 ) (5,687 ) Results of Operations for Oil and Gas Producing Activities $ 3,678 $ (106,670 ) $ (332,535 ) Share of Equity Method Investments (in thousands): Expenses Depletion, Depreciation, Amortization and Accretion $ 813 $ 813 $ 812 Total Costs 813 813 812 Pre-Tax Operating Loss (813 ) (813 ) (812 ) Income Tax Expense (a) (33 ) (10 ) (14 ) Results of Operations for Oil and Gas Producing Activities $ (846 ) $ (823 ) $ (826 ) Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities $ 2,832 $ (107,493 ) $ (333,361 ) (a) Computed using the effective rate for continuing operations for each period: 4.07% in 2017; -1.25% in 2016 and; -1.74% in 2015.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Litigation	23. LITIGATION Litigation Related to Proposed Oil and Gas Leases in Clearfield County, Pennsylvania In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to these proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. On May 9, 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that no contracts were formed between the Company and the plaintiffs. The plaintiffs appealed the dismissal to the Superior Court of Pennsylvania on May 16, 2012. On May 3, 2013, a three-judge panel of the Pennsylvania Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings. In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in the Cardinale and Billotte cases and the plaintiffs in Meeker would be included in a class under the Cardinale and Billotte cases if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, it was consolidated with the Billotte case. The Meeker case has not been consolidated with the Cardinale and Billotte cases. On June 19, 2015, the trial court conducted a hearing on plaintiffs’ motion for class certification in the Cardinale case. On July 6, 2015, the trial court issued an order denying plaintiffs’ motion for class certification. Plaintiffs served notice of their appeal of that decision in August 2015. In June 2016, oral argument was conducted before a three-judge panel of the Pennsylvania Superior Court. On January 17, 2017, the Superior Court vacated the trial court’s order denying class certification and remanded the case to the trial court for a redetermination of whether class certification is proper in the case. On January 31, 2017, the Company filed an Application for Reargument Before En Banc The case has been remanded to the trial court for further consideration. The trial court entered a scheduling order setting a briefing schedule for plaintiffs to file a supplemental motion for class certification. A hearing regarding the supplemental motion for class certification has been scheduled for September 12, 2018. We intend to continue to vigorously defend against these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	24. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. REX ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ and Shares in Thousands Except per Share Data) 2017 March June September December Revenues $ 52,071 $ 47,462 $ 47,975 $ 57,758 Impairment Expense 1,546 3,032 11,877 4,928 Other Costs and Expenses 47,842 54,033 82,632 63,618 Net Income (Loss) Attributable to Rex Energy 2,683 (9,603 ) (46,534 ) (10,788 ) Preferred Stock Dividends (598 ) (598 ) (598 ) (598 ) Net Income (Loss) Attributable to Common Shareholders $ 2,085 $ (10,201 ) $ (47,132 ) $ (11,386 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Income (Loss) $ 0.21 $ (1.03 ) $ (4.76 ) $ (1.13 ) Basic — Weighted Average Shares Outstanding 9,769 9,881 9,906 10,049 Diluted — Net Income (Loss) $ 0.21 $ (1.03 ) $ (4.76 ) $ (1.13 ) Diluted — Weighted Average Shares Outstanding 9,769 9,881 9,906 10,049 2016 March June September December Revenues $ 25,686 $ 31,265 $ 34,039 $ 48,027 Impairment Expense 10,641 25,136 9,563 29,279 Other Costs and Expenses 67,696 59,040 40,953 94,346 Net Loss From Continuing Operations (52,651 ) (52,911 ) (16,477 ) (75,598 ) Net Income (Loss) From Discontinued Operations, Net of Income Taxes (7,490 ) (1,683 ) 21,892 8,203 Net Income (Loss) Attributable to Rex Energy (60,141 ) (54,594 ) 5,415 (67,395 ) Preferred Stock Dividends (2,105 ) (1,723 ) (613 ) (650 ) Effect of Preferred Stock Conversions — 72,316 — 668 Net Income (Loss) Attributable to Common Shareholders $ (62,246 ) $ 15,999 $ 4,802 $ (67,377 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic — Continuing Operations $ (9.78 ) $ 2.45 $ (1.89 ) $ (7.77 ) Basic — Discontinued Operations (1.34 ) (0.23 ) 2.41 0.84 Basic — Net Income (Loss) $ (11.12 ) $ 2.22 $ 0.52 $ (6.93 ) Basic — Weighted Average Shares Outstanding 5,600 7,180 9,080 9,740 Diluted — Continuing Operations $ (9.78 ) $ 2.45 $ (1.89 ) $ (7.77 ) Diluted — Discontinued Operations (1.34 ) (0.23 ) 2.41 0.84 Diluted — Net Income (Loss) $ (11.12 ) $ 2.22 $ 0.52 $ (6.93 ) Diluted — Weighted Average Shares Outstanding 5,600 7,180 9,080 9,740

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	25. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of December 31, 2017, we had $600.3 million of outstanding Senior Notes, as shown in Note 9, Long-Term Debt • Rex Energy I, LLC • Rex Energy Operating Corporation • Rex Energy IV, LLC • PennTex Resources Illinois, Inc. • R.E. Gas Development, LLC The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of December 31, 2017, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of December 31, 2017 and 2016, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years ended December 31, 2017, 2016 and 2015. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2017 ($ in Thousands, Except Share and Per Share Data) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 15,244 $ — $ 3 $ — $ 15,247 Accounts Receivable 25,974 — — — 25,974 Taxes Receivable — — 2,049 — 2,049 Short-Term Derivative Instruments 8,008 — — — 8,008 Inventory, Prepaid Expenses and Other 2,106 — 2,508 — 4,614 Total Current Assets 51,332 — 4,560 — 55,892 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,086,625 — — — 1,086,625 Unevaluated Oil and Gas Properties 186,523 — — — 186,523 Other Property and Equipment 19,640 — — — 19,640 Wells and Facilities in Progress 38,660 — — — 38,660 Pipelines 16,803 — — — 16,803 Total Property and Equipment 1,348,251 — — — 1,348,251 Less: Accumulated Depreciation, Depletion and Amortization (463,899 ) — — — (463,899 ) Net Property and Equipment 884,352 — — — 884,352 Other Assets 44 — — — 44 Intercompany Receivables — — 1,072,637 (1,072,637 ) — Investment in Subsidiaries – Net (2,484 ) — (272,261 ) 274,745 — Long-Term Derivative Instruments (2 ) — 1,721 — 1,719 Deferred Tax Assets - Long-Term — — 130 — 130 Total Assets $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 62,354 $ — $ — $ — $ 62,354 Current Maturities of Long-Term Debt 1,926 — 832,399 — 834,325 Accrued Liabilities 32,214 — 13,004 — 45,218 Short-Term Derivative Instruments 14,892 — — — 14,892 Total Current Liabilities 111,386 — 845,403 — 956,789 Long-Term Derivative Instruments 14,249 — — — 14,249 Long-Term Debt — — — — — Other Long-Term Debt 8,156 — — — 8,156 Other Deposits and Liabilities 7,153 — — — 7,153 Future Abandonment Cost 9,352 — — — 9,352 Intercompany Payables 1,068,231 4,406 — (1,072,637 ) — Total Liabilities 1,218,527 4,406 845,403 (1,072,637 ) 995,699 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 652,917 (177,144 ) 652,917 Accumulated Deficit (462,429 ) (4,406 ) (691,544 ) 451,889 (706,490 ) Total Stockholders’ Equity (285,285 ) (4,406 ) (38,616 ) 274,745 (53,562 ) Total Liabilities and Stockholders’ Equity $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 205,246 $ — $ — $ — $ 205,246 Other Revenue 20 — — — 20 TOTAL OPERATING REVENUE 205,266 — — — 205,266 OPERATING EXPENSES Production and Lease Operating Expense 120,794 — — — 120,794 General and Administrative Expense 16,601 — 1,257 — 17,858 Gain on Disposal of Assets (1,428 ) — — — (1,428 ) Impairment Expense 21,383 — — — 21,383 Exploration Expense 527 — — — 527 Depreciation, Depletion, Amortization and Accretion 58,713 315 — — 59,028 Other Operating Expense 611 — — — 611 TOTAL OPERATING EXPENSES 217,201 315 1,257 — 218,773 LOSS FROM OPERATIONS (11,935 ) (315 ) (1,257 ) — (13,507 ) OTHER INCOME (EXPENSE) Interest Expense (2,288 ) — (46,538 ) — (48,826 ) Loss on Derivatives, Net (131 ) — (1,216 ) — (1,347 ) Other Income (Expense) (270 ) (7 ) 16 — (261 ) Loss on Extinguishment of Debt — — (3,029 ) — (3,029 ) Loss From Equity in Consolidated Subsidiaries (309 ) — (14,337 ) 14,646 — TOTAL OTHER INCOME (EXPENSE) (2,998 ) (7 ) (65,104 ) 14,646 (53,463 ) LOSS BEFORE INCOME TAX (14,933 ) (322 ) (66,361 ) 14,646 (66,970 ) Income Tax (Expense) Benefit 596 13 2,119 — 2,728 NET LOSS (14,337 ) (309 ) (64,242 ) 14,646 (64,242 ) Preferred Stock Dividends — — (2,392 ) — (2,392 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (14,337 ) $ (309 ) $ (66,634 ) $ 14,646 $ (66,634 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Loss $ (14,337 ) $ (309 ) $ (64,242 ) $ 14,646 $ (64,242 ) Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities Depreciation, Depletion, Amortization and Accretion 58,713 315 — — 59,028 Loss on Derivatives 131 — 1,216 — 1,347 Cash Settlements of Derivatives (10,100 ) — — — (10,100 ) Non-Cash Dry Hole Expense 13 — — — 13 Equity-based Compensation Expense (1 ) — 1,232 — 1,231 Impairment Expense 21,383 — — — 21,383 Amortization of Debt Issue Costs — — 1,165 — 1,165 Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 14,063 — 14,063 Loss on Extinguishment of Debt — — 3,029 — 3,029 Gain on Sale of Assets (1,428 ) — — — (1,428 ) Deferred Income Tax Benefit — — (130 ) — (130 ) Other Non-cash Expenses 471 — — — 471 Changes in operating assets and liabilities Accounts Receivable 5,261 — (3 ) — 5,258 Taxes Receivable — — (1,839 ) — (1,839 ) Inventory, Prepaid Expenses and Other Assets (1,159 ) — (901 ) — (2,060 ) Accounts Payable and Accrued Liabilities 6,000 — 8,558 — 14,558 Other Assets and Liabilities (3,210 ) — (49 ) — (3,259 ) NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES 61,737 6 (37,901 ) 14,646 38,488 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 36,631 (6 ) (21,979 ) (14,646 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 31,704 — — — 31,704 Acquisitions of Undeveloped Acreage (3,805 ) — — — (3,805 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (113,411 ) — — — (113,411 ) NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES (48,881 ) (6 ) (21,979 ) (14,646 ) (85,512 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 217,000 — 217,000 Repayments of Long-Term Debt and Lines of Credit — — (145,170 ) — (145,170 ) Repayments of Loans and Other Notes Payable (1,306 ) — — — (1,306 ) Debt Issuance Costs — — (10,754 ) — (10,754 ) Dividends Paid on Preferred Stock — — (1,196 ) — (1,196 ) NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (1,306 ) — 59,880 — 58,574 NET INCREASE IN CASH 11,550 0 (0 ) 0 11,550 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 15,244 $ 0 $ 3 $ 0 $ 15,247 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2016 ($ in Thousands, Except Share and Per Share Data) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 3,694 $ — $ 3 $ — $ 3,697 Accounts Receivable 22,609 — 2,839 — 25,448 Taxes Receivable — — 211 — 211 Short-Term Derivative Instruments 1,873 — — — 1,873 Inventory, Prepaid Expenses and Other 2,521 — 25 — 2,546 Total Current Assets 30,697 — 3,078 — 33,775 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,053,461 — — — 1,053,461 Unevaluated Oil and Gas Properties 215,794 — — — 215,794 Other Property and Equipment 21,401 — — — 21,401 Wells and Facilities in Progress 21,964 — — — 21,964 Pipelines 18,029 — — — 18,029 Total Property and Equipment 1,330,649 — — — 1,330,649 Less: Accumulated Depreciation, Depletion and Amortization (475,205 ) — — — (475,205 ) Net Property and Equipment 855,444 — — — 855,444 Deferred Financing Costs and Other Assets—Net 2,492 — — — 2,492 Intercompany Receivables — — 1,035,713 (1,035,713 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments (723 ) — 2,935 — 2,212 Total Assets $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 40,712 $ — $ — $ — $ 40,712 Current Maturities of Long-Term Debt 764 — — — 764 Accrued Liabilities 32,328 421 4,458 — 37,207 Short-Term Derivative Instruments 25,025 — — — 25,025 Total Current Liabilities 98,829 421 4,458 — 103,708 Long-Term Derivative Instruments 7,227 — — — 7,227 Long-Term Debt — — 751,946 — 751,946 Other Long-Term Debt 3,409 — — — 3,409 Other Deposits and Liabilities 8,671 — — — 8,671 Future Abandonment Cost 8,736 — 8,736 Intercompany Payables 1,032,050 3,663 — (1,035,713 ) — Total Liabilities 1,158,922 4,084 756,404 (1,035,713 ) 883,697 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 650,669 (177,144 ) 650,669 Accumulated Deficit (450,544 ) (4,084 ) (493,332 ) 307,506 (640,454 ) Total Stockholders’ Equity (273,400 ) (4,084 ) 157,348 130,362 10,226 Total Liabilities and Stockholders’ Equity $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 139,000 $ — $ — $ — $ 139,000 Other Revenue 17 — — — 17 TOTAL OPERATING REVENUE 139,017 — — — 139,017 OPERATING EXPENSES Production and Lease Operating Expense 104,699 — — — 104,699 General and Administrative Expense 17,488 5 3,128 — 20,621 Gain on Disposal of Assets (4,121 ) — — — (4,121 ) Impairment Expense 74,624 (5 ) — — 74,619 Exploration Expense 2,177 1 — — 2,178 Depreciation, Depletion, Amortization and Accretion 62,849 25 — — 62,874 Other Operating Expense 10,754 — — — 10,754 TOTAL OPERATING EXPENSES 268,470 26 3,128 — 271,624 LOSS FROM OPERATIONS (129,453 ) (26 ) (3,128 ) — (132,607 ) OTHER INCOME (EXPENSE) Interest Expense (1,326 ) — (42,193 ) — (43,519 ) Gain (Loss) on Derivatives, Net (34,285 ) — 1,770 — (32,515 ) Other Income (Expense) 41 — (2,165 ) — (2,124 ) Debt Exchange Expense — — (9,063 ) — (9,063 ) Gain on Extinguishment of Debt — 24,627 — 24,627 Income (Loss) From Equity in Consolidated Subsidiaries (94 ) 94 (146,344 ) 146,344 — TOTAL OTHER INCOME (EXPENSE) (35,664 ) 94 (173,368 ) 146,344 (62,594 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (165,117 ) 68 (176,496 ) 146,344 (195,201 ) Income Tax Expense (2,060 ) — (376 ) — (2,436 ) NET INCOME (LOSS) FROM CONTINUING OPERATIONS (167,177 ) 68 (176,872 ) 146,344 (197,637 ) Income (Loss) From Discontinued Operations, Net of Income Tax 20,887 (122 ) 157 20,922 NET LOSS (146,290 ) (54 ) (176,715 ) 146,344 (176,715 ) Preferred Stock Dividends — — (5,091 ) — (5,091 ) Effect of Preferred Stock Conversion — — 72,984 — 72,984 NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (146,290 ) $ (54 ) $ (108,822 ) $ 146,344 $ (108,822 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Loss $ (146,290 ) $ (54 ) $ (176,715 ) $ 146,344 $ (176,715 ) Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities Depreciation, Depletion, Amortization and Accretion 67,915 60 — — 67,975 Gain (Loss) on Derivatives 34,285 — (1,770 ) — 32,515 Cash Settlements of Derivatives 32,571 — — — 32,571 Non-Cash Dry Hole Expense 905 — — — 905 Equity-based Compensation Expense 40 — 2,919 — 2,959 Impairment Expense 78,160 2 78,162 (78,162 ) 78,162 Amortization of Debt Issuance Costs — — 1,640 — 1,640 Amortization of Bond Discounts and Premiums — — (100 ) — (100 ) Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 19,603 — 19,603 Gain on Extinguishment of Debt — — (24,627 ) — (24,627 ) (Gain) Loss on Sale of Assets (34,697 ) 46 — — (34,651 ) Other Non-cash (Income) Expense (208 ) — 230 — 22 Changes in operating assets and liabilities Accounts Receivable (44,354 ) (863 ) 38,803 — (6,414 ) Inventory, Prepaid Expenses and Other Assets 906 — — — 906 Accounts Payable and Accrued Liabilities 8,815 — (6,020 ) — 2,795 Other Assets and Liabilities (1,953 ) 3 — — (1,950 ) NET CASH USED BY OPERATING ACTIVITIES (3,905 ) (806 ) (67,875 ) 68,182 (4,404 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 3,587 (94 ) 64,689 (68,182 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 39,904 980 — — 40,884 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (6,671 ) (41 ) — — (6,712 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (48,943 ) (39 ) — — (48,982 ) NET CASH PROVIDED BY INVESTING ACTIVITIES 7,338 806 64,689 (68,182 ) 4,651 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 71,400 — 71,400 Repayments of Long-Term Debt and Lines of Credit — — (65,230 ) — (65,230 ) Repayments of Loans and Other Notes Payable (828 ) — — — (828 ) Debt Issuance Costs — — (2,983 ) — (2,983 ) NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (828 ) — 3,187 — 2,359 NET INCREASE IN CASH 2,605 0 1 — 2,606 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 3,694 $ 0 $ 3 $ — $ 3,697 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 138,707 $ — $ — $ — $ 138,707 Other Revenue 42 — — — 42 TOTAL OPERATING REVENUE 138,749 — — — 138,749 OPERATING EXPENSES Production and Lease Operating Expense 93,892 — — — 93,892 General and Administrative Expense 20,849 — 5,845 — 26,694 Gain on Disposal of Assets (540 ) — — — (540 ) Impairment Expense 282,833 411 — — 283,244 Exploration Expense 2,616 1 — — 2,617 Depreciation, Depletion, Amortization and Accretion 85,839 5 — — 85,844 Other Operating Expense 5,603 — — — 5,603 TOTAL OPERATING EXPENSES 491,092 417 5,845 — 497,354 LOSS FROM OPERATIONS (352,343 ) (417 ) (5,845 ) — (358,605 ) OTHER INCOME (EXPENSE) Interest Expense (248 ) — (47,535 ) — (47,783 ) Gain on Derivatives, Net 59,242 — 934 — 60,176 Other Expense (129 ) — — — (129 ) Loss From Equity Method Investments (411 ) — — — (411 ) Income (Loss) From Equity in Consolidated Subsidiaries (429 ) 429 (309,250 ) 309,250 — TOTAL OTHER INCOME (EXPENSE) 58,025 429 (355,851 ) 309,250 11,853 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (294,318 ) 12 (361,696 ) 309,250 (346,752 ) Income Tax Expense (5,111 ) (7 ) (912 ) — (6,030 ) NET INCOME (LOSS) FROM CONTINUING OPERATIONS (299,429 ) 5 (362,608 ) 309,250 (352,782 ) Income (Loss) From Discontinued Operations, Net of Income Taxes (45,546 ) 37,965 (670 ) — (8,251 ) NET INCOME (LOSS) (344,975 ) 37,970 (363,278 ) 309,250 (361,033 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 2,245 — — 2,245 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY (344,975 ) 35,725 (363,278 ) 309,250 (363,278 ) Preferred Stock Dividends — — (9,660 ) — (9,660 ) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (344,975 ) $ 35,725 $ (372,938 ) $ 309,250 $ (372,938 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (344,975 ) $ 37,970 $ (363,278 ) $ 309,250 $ (361,033 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities Loss on Equity Method Investments 411 — — — 411 Depreciation, Depletion, Amortization and Accretion 105,555 3,230 — (3,963 ) 104,822 Gain on Derivatives (59,242 ) — (934 ) — (60,176 ) Cash Settlements of Derivatives 54,859 — 934 — 55,793 Non-Cash Dry Hole Expense 199 136 — (5 ) 330 Equity-based Compensation Expense 99 — 6,450 — 6,549 Impairment Expense 345,892 1,396 345,892 (347,405 ) 345,775 Amortization of Debt Issuance Costs 17 13 2,015 — 2,045 Amortization of Bond Discounts and Premiums — — (381 ) — (381 ) Gain on Sale of Assets (477 ) (44 ) — — (521 ) Gain on Sale of Water Solutions — — (57,778 ) — (57,778 ) Other Non-cash Income (Expense) (218 ) (346 ) — — (564 ) Changes in operating assets and liabilities Accounts Receivable 24,240 (453 ) 429 (2,537 ) 21,679 Inventory, Prepaid Expenses and Other Assets (431 ) (142 ) 5 — (568 ) Accounts Payable and Accrued Liabilities (20,008 ) (4,969 ) (515 ) 2,537 (22,955 ) Other Assets and Liabilities (2,497 ) (73 ) 27 — (2,543 ) NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES 103,424 36,718 (67,134 ) (42,123 ) 30,885 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 96,664 (37,425 ) (100,198 ) 40,959 — Proceeds from Joint Venture Acreage Management 58 — — — 58 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 9,766 560 66,900 — 77,226 Proceeds from Joint Venture 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (27,963 ) (279 ) — — (28,242 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (214,450 ) (7,813 ) — 1,164 (221,099 ) NET CASH PROVIDED USED BY INVESTING ACTIVITIES (119,314 ) (44,957 ) (33,298 ) 42,123 (155,446 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 35,814 193,500 — 229,314 Repayments of Long-Term Debt and Lines of Credit — (26,335 ) (82,000 ) — (108,335 ) Repayments of Loans and Other Notes Payable (999 ) (520 ) — — (1,519 ) Debt Issuance Costs — (3 ) (1,411 ) — (1,414 ) Distribution by the Partners of Consolidated Subsidiary — (830 ) — — (830 ) Dividends Paid on Preferred Stock — — (9,660 ) — (9,660 ) NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (999 ) 8,126 100,429 — 107,556 NET DECREASE IN CASH (16,889 ) (113 ) (3 ) — (17,005 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH - ENDING $ 1,089 $ (0 ) $ 2 $ — $ 1,091

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	26. SUBSEQUENT EVENTS Sale of Westmoreland Properties On March 13, 2018, the Company, entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which the Company agreed to sell to XPR certain of its non-operated oil and gas interests in 61 wells located in Westmoreland and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to the Company. In a related transaction, the Company entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which the Company 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. 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.

Summary Of Significant Accoun33

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. Estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved natural gas, NGL and oil reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of condensate and natural gas, interest rates and our ability to generate future income.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2017 and 2016, our Cash and Cash Equivalents consisted of only cash.
Accounts Receivable	Accounts Receivable Our trade accounts receivable, which are primarily from natural gas, NGLs and condensate sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2017 and 2016 were $0.1 million and $0.1 million, respectively. To the extent actual quantities and values of natural gas, NGLs and condensate are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets. At December 31, 2017, we carried approximately $22.9 million in production receivable, of which approximately $19.3 million were production receivables due from our three largest purchasers. At December 31, 2016, we carried approximately $22.2 million in production receivables, of which approximately $17.5 million were production receivables due from three purchasers. In addition, we carried approximately $2.5 million in receivables at December 31, 2017 and $2.7 million at December 31, 2016 that was in relation to our joint operations with Sumitomo Corporation, Benefit Street Partners, LLC and ArcLight Capital Partners, LLC.
Inventory	Inventory Inventory is valued at the lower of cost or market value and consists of our ownership interest in NGLs and condensate held in terminal tanks located in the field. NGL and condensate cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.
Natural Gas, NGLs, and Oil Property, Depreciation and Depletion	Natural Gas , NGLs, and Oil Property, Depreciation and Depletion We account for natural gas, NGL and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proven natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of condensate, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2017, 2016 and 2015, we capitalized interest costs of $1.7 million, $2.7 million and $7.7 million, respectively. Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable natural gas and oil are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years. We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future natural gas, NGL and condensate prices are based on forward strip prices for NYMEX oil and various natural gas markets that are relevant to our operations. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved natural gas and oil properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved natural gas, NGL and condensate properties, we analyze the level and success of current development, changes in future development plans and changes in market value. If it is determined that it is unlikely for an unproved property to be successfully developed prior to the lease expiration or extension, an impairment of the respective unproved property is recognized in the period in which that determination is made. Performing the impairment evaluations requires use of judgment since the results are dependent on future events, including the timing of future capital expenditures, production and the intent to develop properties, among others. We recognized approximately $21.4 million, $74.6 million and $283.2 million of impairment from continuing operations on certain natural gas, NGL and condensate properties for the years ended December 31, 2017, 2016 and 2015, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depletion are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.
Natural Gas, NGL and Condensate Reserve Quantities	Natural Gas, NGL and Condensate Reserve Quantities Our estimate of proved reserves is based on the quantities of natural gas, NGLs and condensate that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2017 and 2016, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our natural gas, NGLs, and condensate reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineers estimate reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.
Future Abandonment Cost	Future Abandonment Cost Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Accretion expense from continuing operations during the years ended December 31, 2017, 2016 and 2015 totaled approximately $1.9 million, $1.0 million and $1.0 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2017 and 2016, approximately $0.6 million and $1.1 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Liabilities on our Consolidated Balance Sheets. During 2017 and 2016, we recognized an increase of $0.8 million and $1.9 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells. December 31, 2017 (in thousands) December 31, 2016 (in thousands) Beginning Balance $ 9,865 $ 11,934 Asset Retirement Obligation Incurred 1,061 575 Asset Retirement Obligation Settled (3,187 ) (671 ) Asset Retirement Obligation Cancelled or Sold Properties (549 ) (4,876 ) Asset Retirement Obligation Revision of Estimated Obligation 834 1,918 Asset Retirement Obligation Accretion Expense 1,915 985 Total Future Abandonment Costs $ 9,939 $ 9,865
Revenue Recognition	Revenue Recognition Natural gas, NGLs, and condensate revenue is recognized when the natural gas, NGLs, or condensate is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of condensate sales, title is transferred to the purchaser when the condensate leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, wellhead gas volumes are first processed through various third-party gas processing facilities to separate the raw (“wet”) gas into NGL products and natural gas. Title to NGL and natural gas products transfers to the purchaser when the separated product volumes are metered for sale either at the exit flange of a processing facility, or the inlet flange of a purchaser’s designated delivery point. Sales prices for purchased volumes are defined in sales contracts and are readily determinable based on certain publicly available indices. Our commodity purchasers have historically made payment for natural gas, NGL and condensate purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. To the extent actual quantities and values of natural gas, NGLs and condensate are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in our Consolidated Balance Sheets, and as natural gas, NGL, and condensate Sales in our Consolidated Statements of Operations. Effective January 1, 2018, we adopted ASC 606, Revenue from Contracts with Customers. Recently Issued Accounting Pronouncements – Revenue Recognition
Derivative Instruments	Derivative Instruments We use put and call options (collars), fixed rate swap contracts, puts, basis swaps and three-way collars to manage price risks in connection with the sale of natural gas, NGLs, and condensate. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third parties. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2017, 2016 and 2015 we did not have any derivative instruments designated for hedge accounting. For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on natural gas, NGL, and oil production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments
Contingent Liabilities	Contingent Liabilities A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information.
Income Taxes	Income Taxes We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to oil and gas properties and other taxable differences. Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rates. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized. This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position. The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 11, Income Taxes,
Stock-based Compensation	Stock-based Compensation We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 15, Employee Benefit and Equity Plans, In March 2016, the Financial Account Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
Earnings per Common Share	Earnings per Common Share Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2017, we had 10,244,394 common shares outstanding, 86,331 options outstanding and 2,050 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 200,475 restricted stock awards, of which approximately 38,261 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share
Recent Accounting Pronouncements	Recent Accounting Pronouncements From May 2014 through September 2017, the FASB issued several ASUs revising certain revenue accounting standards, codified together as Accounting Standards Codification (“ASC”) 606 – Revenue from Contracts with Customers The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. is effective for interim and annual periods beginning af permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented and any cumulative effect of applying the standard recognized in the earliest period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. We have adopted a the modified retrospective method. This allows us t new contracts entered into after January 1, 2018 existing contracts for w revenue not expect the standard to res financial position implemen business processes, systems, and controls to support recogn . disclosures will be describe the nature, amount, timing and uncertainty of revenue and cash flows f and remaining perf During 2016 and 2017, we evaluated our contracts with customers under ASC 606. We have determined that adoption of the standard would not result in any material change to the timing or method of recognizing revenue for our natural gas, NGL, and condensate commodity sales under contracts with our customers. The impact of adopting ASC 606 relates primarily to contract arrangements wherein title to the good or service and risk of loss transfer from seller to purchaser at different points. Our sales contracts with customers specify that title to purchased commodity volumes and the risk of loss associated with those goods transfers to the purchaser at the same point in time, which is consistent with the ASC 606 revenue recognition model. Our analysis of contract performance obligations and transaction pricing structures under ASC 606 is not materially different from our obligations and pricing structures identified under our current revenue recognition model. ASC 606 requires evaluation of contracts with customers to determine whether the selling party in a contract for goods or services is acting in the capacity of the Principal or as an Agent, as defined in the standard. This determination is then applied to evaluate whether revenues earned from sales to a customer are to be reported in the statement of operations as gross revenue receipts (in our instance commodity volumes sold multiplied by the contract specified sales price), or reported net of various costs incurred by the seller to fulfill the performance obligation. To produce the various saleable commodities that we supply to our customers from our wellhead wet gas and to transport products to the physical points of sale, we incur expenses including gas plant processing fees, gathering and compressions fees, transportation charges, and fees for pipeline capacity commitments. We have determined that we are the principal in all our current commodity sales contracts, and accordingly we record sales revenue at the gross sales price received. Our expense associated with processing and delivering the products to our buyers are reported as components of Production and Lease Operating Expense In February 2016, the FASB issued ASU 2016-02, Leases • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

Summary Of Significant Accoun34

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Asset Retirement Obligations	We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells. December 31, 2017 (in thousands) December 31, 2016 (in thousands) Beginning Balance $ 9,865 $ 11,934 Asset Retirement Obligation Incurred 1,061 575 Asset Retirement Obligation Settled (3,187 ) (671 ) Asset Retirement Obligation Cancelled or Sold Properties (549 ) (4,876 ) Asset Retirement Obligation Revision of Estimated Obligation 834 1,918 Asset Retirement Obligation Accretion Expense 1,915 985 Total Future Abandonment Costs $ 9,939 $ 9,865

Business and Oil and Gas Prop35

Business and Oil and Gas Property Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Average Spot Price	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 December 31, 2017, the first five of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds relate to those measurement periods. As of December 31, 2017, we have the potential to receive up to $5.4 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 10, Fair Value of Financial Instruments and Derivative Instruments Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).

Discontinued Operations_Asset36

Discontinued Operations/Assets Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2017
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. December 31, ($ in Thousands) 2017 2016 2015 Revenues: Field Services Revenue $ — $ — $ 33,086 Total Operating Revenue — — 33,086 Costs and Expenses: General and Administrative Expense — — 1,961 Depreciation, Depletion, Amortization and Accretion — — 78 Impairment Expense — — — Field Service Operating Expense — — 25,981 Gain on Disposal of Asset — — (44 ) Interest Expense — — 487 Other (Income) Expense — — (57,589 ) Total Costs and Expenses (Income) — — (29,126 ) Income from Discontinued Operations Before Income Taxes — — 62,212 Income Tax Expense — — (24,227 ) Income from Discontinued Operations, net of taxes $ — $ — $ 37,985
Illinois Basin Operations
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. The sale of our Illinois Basin assets and operations does not include any of our derivative contracts or positions related to our Illinois Basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the years ended December 31, 2017, 2016 and 2015. December 31, ($ in Thousands) 2017 2016 2015 Revenues: Oil Sales $ — $ 11,282 $ 33,244 Total Operating Revenue — 11,282 33,244 Costs and Expenses: Production and Lease Operating Expense — 11,033 25,099 General and Administrative Expense — 1,002 2,741 (Gain) Loss on Disposal of Assets — (30,530 ) 63 Impairment Expense — 3,543 62,531 Exploration Expense — 143 394 Depreciation, Depletion, Amortization and Accretion — 5,100 18,900 Interest Expense — 4 23 Other (Income) Expense — 65 (14 ) Total Costs and Expenses — (9,640 ) 109,737 Income (Loss) from Discontinued Operations Before Income Taxes — 20,922 (76,493 ) Income Tax Benefit — — 30,257 Income (Loss) from Discontinued Operations, net of taxes $ — $ 20,922 $ (46,236 ) Production: Crude Oil (Bbls) — 310,388 729,251

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	At December 31, 2017 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.8 million, $0.9 million and $1.0 million for the years ended December 31, 2017, 2016 and 2015, respectively. Lease commitments by year for each of the next five years are presented in the table below. ($ in Thousands) 2018 $ 1,013 2019 1,020 2020 888 2021 475 2022 485 Thereafter — Total $ 3,881
Minimum Net Obligations under Sales, Gathering and Transportation Agreements	Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2018 $ 50,313 2019 50,864 2020 49,526 2021 46,574 2022 46,139 Thereafter 464,599 Total $ 708,015

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Components of Long-Term Debt and Lines of Credit	December 31, 2017 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 189,500 $ (4,711 ) $ (2,761 ) $ — $ 182,028 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ 20 $ (80 ) $ — $ 7,273 6.25% Senior Notes due 2022 5,363 — (67 ) — 5,296 1% / 8% Second Lien Senior Notes due 2020 587,606 (13,991 ) 33,751 30,436 637,802 $ 600,302 $ (13,971 ) $ 33,604 $ 30,436 $ 650,371 Other Long-Term Debt Long-Term Capital Leases - 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 (1,926 ) $ 8,156 December 31, 2016 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Senior Secured Line of Credit, Net Revolving Senior Credit Facility $ 117,670 $ — $ (3,885 ) $ — $ 113,785 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,573 $ 26 $ (107 ) $ — $ 7,492 6.25% Senior Notes due 2022 5,648 — (82 ) — 5,566 1% / 8% Second Lien Senior Notes due 2020 587,956 (3,627 ) 8,098 32,676 625,103 $ 601,177 $ (3,601 ) $ 7,909 $ 32,676 $ 638,161 Other Long-Term Debt Long-Term Capital Leases and Other Notes Payable- Equipment Financing Due March, 2021 $ 760 Due June, 2021 2,225 Due September, 2021 1,174 Total Capital Lease Obligations $ 4,159 Other Notes Payable 14 Total Capital Lease and Note Payable Obligations $ 4,173 Less: Current Portion of Capital Leases and Other Notes Payable (764 ) $ 3,409
Principal Maturity Schedule for Total Debt Outstanding	The following is the principal maturity schedule for total debt outstanding as of December 31, 2017: ($ in thousands) 2018 (a) $ 791,728 2019 2,252 2020 2,636 2021 2,462 2022 806 Thereafter — Total (b) $ 799,884 a) Due to existing and anticipated covenant violations, the Company’s Term Loan and Senior Notes were classified as current at December 31, 2017. b) Does not include $18.7 million net unamortized premium/discount, $30.8 million of net unamortized debt issuance costs, and $30.4 million of unamortized deferred gain on debt restructurings. Covenant Violations The audit report the Company received with respect to its consolidated financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under the senior term loan facility. See “Going Concern” in Note 1 – Basis of Presentation and Principals of Consolidation for information regarding additional events of default that have occurred subsequent to December 31, 2017.

Fair Value Of Financial Instr39

Fair Value Of Financial Instruments And Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	Derivative Instruments from Continuing Operations The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015: For the Year Ended December 31, ($ in Thousands) 2017 2016 2015 Oil $ (500 ) $ (1,515 ) $ 7,132 Natural Gas 13,889 (15,036 ) 37,647 NGLs (13,520 ) (17,788 ) 14,839 Interest Rate — — 934 Refined Products — 54 (376 ) Contingent Consideration (1,216 ) 1,770 — Gain (Loss) on Derivatives, Net $ (1,347 ) $ (32,515 ) $ 60,176
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2017 consisted of the following: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2018 - Swaps 95,000 Bbls $ — $ — $ — $ 53.93 $ (518 ) 2018 - Collars 18,000 Bbls — 53.00 60.00 — (31 ) 2018 - Three-Way Collars 72,000 Bbls 42.29 51.46 61.38 — (92 ) 2019 - Swaps 31,500 Bbls — — — 51.00 (90 ) 2019 - Collars 60,250 Bbls — 45.00 55.07 — (100 ) 2019 - Three-Way Collars 50,250 Bbls 38.81 48.81 58.35 — (94 ) 2020 - Swaps 24,000 Bbls — — — 51.00 (90 ) 2020 - Collars 71,750 Bbls 45.00 55.10 (133 ) 2020 - Three-Way Collars 29,600 Bbls 39.24 49.24 56.99 — (52 ) 2021 - Swaps 6,000 Bbls — — — 51.00 (22 ) 2021 - Collars 63,750 Bbls — 45.00 55.02 — (123 ) 2021 - Three-Way Collars 24,000 Bbls 37.50 47.50 60.25 — (12 ) 2022 - Collars 36,000 Bbls — 45.00 54.75 — (69 ) 2022 - Three-Way Collars 6,000 Bbls 37.50 47.50 60.25 — (3 ) 588,100 Bbls $ (1,429 ) Natural Gas 2018 - Swaps 15,335,000 Mcf $ — $ — $ — $ 3.10 $ 3,733 2018 - Three-Way Collars 10,600,000 Mcf 2.33 2.90 3.52 — 1,672 2018 - Calls 5,810,000 Mcf — — 3.97 — (154 ) 2018 - Collars 4,415,000 Mcf — 2.66 3.10 — 37 2018 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.83 ) (3,604 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) 173 2019 - Swaps 10,470,000 Mcf — — — 2.84 154 2019 - Three-Way Collars 8,205,000 Mcf 2.27 2.77 3.40 — 132 2019 - Collars 7,520,500 Mcf — 2.54 3.04 — (295 ) 2019 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.84 ) (3,570 ) 2020 - Swaps 4,560,000 Mcf — — — 2.87 13 2020 - Three-Way Collars 4,555,000 Mcf 2.23 2.73 3.30 — 113 2020 - Collars 4,720,000 Mcf — 2.51 3.05 — (183 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.84 ) (1,945 ) 2021 - Swaps 3,875,000 Mcf — — — 2.77 (87 ) 2021 - Three-Way Collars 3,037,500 Mcf 2.17 2.67 3.15 — (30 ) 2021 - Collars 2,737,500 Mcf — 2.50 3.05 — (134 ) 2021 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 2022 - Swaps 2,730,000 Mcf — — — 2.73 (91 ) 2022 - Three-Way Collars 2,047,500 Mcf 2.15 2.65 3.10 — (58 ) 2022 - Collars 2,047,500 Mcf — 2.50 3.05 — (101 ) 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (401 ) 154,735,500 Mcf $ (5,829 ) NGLs 2018 - C3+ NGL Swaps 1,367,572 Bbls $ — $ — $ — $ 33.30 $ (10,254 ) 2018 - Ethane Swaps 1,247,500 Bbls — — — 12.92 900 2019 - C3+ NGL Swaps 705,922 Bbls — — — 30.65 (2,750 ) 2019 - C5 Collars 113,040 Bbls — 45.00 54.83 — (308 ) 2019 - Ethane Swaps 727,500 Bbls — — — 12.98 306 2019 - C5 Three-Way Collars 8,472 Bbls — 32.31 50.00 55.75 (17 ) 2020 - C3+ NGL Swaps 271,276 Bbls — — — 37.63 (1,157 ) 2020 - C5 Collars 28,260 Bbls — 45.00 54.83 — (77 ) 2020 - Ethane Swaps 448,500 Bbls — — — 12.83 (9 ) 2020 - C5 Three-Way Collars 28,134 Bbls — 32.31 50.00 55.75 (49 ) 2021 - C3+ NGL Swap 158,112 Bbls — — — 45.62 (376 ) 2021 - Ethane Swaps 251,000 Bbls — — — 12.77 (3 ) 2022 - C3+ NGL Swap 48,984 Bbls — — — 50.56 (74 ) 2022 - Ethane Swaps 111,500 Bbls — — — 12.69 (9 ) 5,515,772 Bbls $ (13,877 )
Combined Fair Value of Derivatives	The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016 is summarized below. December 31, December 31, ($ in Thousands) 2017 2016 Short-Term Derivative Assets: NGL—Swaps 928 — Natural Gas—Swaps 3,734 206 Natural Gas—Cap Swaps — 61 Natural Gas—Collars 183 — Natural Gas—Basis Swaps 191 232 Natural Gas—Three-Way Collars 1,721 151 Contingent Consideration - Sale of Illinois Basin 1,251 1,223 Total Short-Term Derivative Assets $ 8,008 $ 1,873 Long-Term Derivative Assets: NGL—Swaps 409 — Natural Gas—Swaps 411 206 Natural Gas—Basis Swaps — 293 Natural Gas—Three-Way Collars 429 — Contingent Consideration - Sale of Illinois Basin 470 1,713 Total Long-Term Derivative Assets $ 1,719 $ 2,212 Total Derivative Assets $ 9,727 $ 4,085 Short-Term Derivative Liabilities: Crude Oil—Collars $ (31 ) $ (86 ) Crude Oil—Deferred Put Spread — (9 ) Crude Oil—Three-Way Collars (92 ) (132 ) Crude Oil—Swaps (518 ) (220 ) NGL—Swaps (10,281 ) (9,895 ) Natural Gas—Three-Way Collars (49 ) (2,397 ) Natural Gas—Cap Swaps — (3,364 ) Natural Gas—Collars (146 ) (873 ) Natural Gas—Basis Swaps (3,621 ) (640 ) Natural Gas—Call (154 ) (1,478 ) Natural Gas—Swaption — (1,258 ) Natural Gas—Swaps — (4,673 ) Total Short - Term Derivative Liabilities $ (14,892 ) $ (25,025 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars $ (161 ) $ (58 ) Crude Oil—Swaps (202 ) (146 ) Crude Oil—Collars (425 ) — NGL—Swaps (4,482 ) (2,200 ) NGL—Collars (385 ) — NGL—Three Way Collars (66 ) — Natural Gas—Swaps (423 ) (1,004 ) Natural Gas—Swaption — (167 ) Natural Gas—Basis Swaps (7,120 ) (1,260 ) Natural Gas—Collars (713 ) (115 ) Natural Gas—Call — (491 ) Natural Gas—Three-Way Collars (272 ) (1,786 ) Total Long-Term Derivative Liabilities $ (14,249 ) $ (7,227 ) Total Derivative Liabilities $ (29,141 ) $ (32,252 )
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value	The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at December 31, 2017 Using: ($ 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 ) $ — Fair Value Measurements at December 31, 2016 Using: ($ in Thousands) Total Carrying Value as of December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (28,167 ) $ — $ (28,167 ) $ —
Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3)	The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2017 and 2016 (in thousands): For the Year Ended December 31, ($ in Thousands) 2017 2016 Beginning Balance of Level 3 $ — $ (5,506 ) Changes in Fair Value — 7,249 Transfers out of Level 3 — (1,564 ) Purchases — — Settlements Received — (179 ) Ending Balance of Level 3 $ — $ —
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: December 31, 2017 December 31, 2016 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 650,371 $ 265,438 $ 638,161 $ 147,605 Secured Lines of Credit 182,028 182,028 113,785 113,785 Capital Leases and Other Obligations 10,082 7,138 4,173 3,234 Total $ 842,481 $ 454,604 $ 756,119 $ 264,624

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Expense from Continuing Operations	Our income tax expense from continuing operations consisted of the following: For the Years Ended December 31, ($ in Thousands) 2017 2016 2015 Current: Federal $ (2,001 ) $ 1,839 $ — State (597 ) 597 - Deferred: Federal (130 ) — 5,773 State — — 257 Income Tax (Benefit) Expense $ (2,728 ) $ 2,436 $ 6,030
Reconciliation of Income Tax Expense Using Statutory Rate Compared With Actual Income Tax Expense	A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows: ($ in Thousands) Year Ended December 31, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 Income (Loss) from continuing operations before noncontrolling interests and income taxes $ (66,970 ) $ (195,201 ) $ (346,752 ) Statutory U.S. income tax rate 35.0 % 35.0 % 35.0 % Tax expense recognized using statutory U.S. income tax rate $ (23,440 ) $ (68,320 ) $ (121,363 ) State income taxes, net of federal income tax benefit (1,723 ) (3,632 ) (17,137 ) Change in future rates 79,322 (400 ) (212 ) Permanent differences 1,130 2,264 1,784 Change in valuation allowances (57,622 ) 72,784 143,566 Other (395 ) (260 ) (608 ) Total income tax expense $ (2,728 ) $ 2,436 $ 6,030 Effective income tax rate 4.07 % -1.25 % -1.74 %
Components of Deferred Tax Assets (Liabilities)	Deferred tax assets (liabilities) are comprised of the following at December 31, 2017 and 2016: For the Years Ended December 31, ($ in Thousands) 2017 2016 Tax effects of temporary differences for: Assets: Asset retirement obligation $ 2,647 $ 3,955 Deferred compensation plans 600 1,581 Compensation Accruals 390 762 Unrealized loss on derivatives 5,457 11,760 Net operating loss carryforwards 126,820 79,531 Deferred Financing Costs (a) 98,065 182,519 Gas Transportation Capacity Commitments 1,697 3,031 Deferred revenue timing differences 388 443 Organization costs 213 391 Percentage depletion carryforward 2,155 2,717 AMT credits 130 2,131 Timing differences - tax partnerships 465 1,046 Other 217 331 Valuation allowances (154,416 ) (212,041 ) Total Deferred Tax Assets net of Valuation Allowances $ 84,828 $ 78,157 Liabilities: Book basis of oil and gas properties in excess of tax basis (84,622 ) (77,690 ) Other (76 ) (467 ) Total Deferred Tax Liabilities $ (84,698 ) $ (78,157 ) Net Deferred Tax Asset $ 130 $ — (a) Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016.
Expirations by Year for Federal and State Net Operating Loss Carryforwards	The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected): Year of Expiration Net Operating Loss Carryforwards (in thousands) 2023 2 2024 — 2025 — 2026 572 2027 1,183 2028 35 2029 18 2030 95 2031 2,089 2032 36 2033 2,227 2034 2,730 2035 39,280 2036 15,236 2037 63,317 Total 126,820

Earnings Per Common Share (Tabl

Earnings Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earning Per Common Share	The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data): Year Ended December 31, Year Ended December 31, Year Ended December 31, (in thousands, except per share amounts) 2017 2016 2015 Numerator: Net Loss From Continuing Operations $ (64,242 ) $ (197,637 ) $ (352,782 ) Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests — 20,922 (10,496 ) Less: Preferred Stock Dividends (2,392 ) (5,091 ) (9,660 ) Effect of Preferred Stock Conversions — 72,984 — Net Loss Attributable to Common Shareholders $ (66,634 ) $ (108,822 ) $ (372,938 ) Denominator: Weighted Average Common Shares Outstanding - Basic 9,902 7,926 5,439 Effect of Dilutive Securities: Employee Stock Options — — — Employee Performance-Based Restricted Stock Awards — — — Effect of Assumed Conversions of Preferred Stock — — — Weighted Average Common Shares Outstanding - Diluted 9,902 7,926 5,439 Earnings per Common Share Attributable to Rex Energy Common Shareholders(a): Basic — Net Loss From Continuing Operations $ (6.73 ) $ (16.37 ) $ (66.64 ) — Net Income (Loss) From Discontinued Operations — 2.64 (1.93 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (6.73 ) $ (13.73 ) $ (68.57 ) Diluted — Net Loss From Continuing Operations $ (6.73 ) $ (16.37 ) $ (66.64 ) — Net Income (Loss) From Discontinued Operations — 2.64 (1.93 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (6.73 ) $ (13.73 ) $ (68.57 ) (a) All earnings per share amounts are attributable to Rex common shareholders.

Employee Benefit And Equity P42

Employee Benefit And Equity Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Stock Option Activity	A summary of the stock option activity is as follows: Number of Shares Weighted-Average Exercise Price Weighted-Average Remaining Term (in years) Aggregate Intrinsic Value (in thousands) Options outstanding December 31, 2014 40,268 $ 108.20 Granted 8,000 44.80 Exercised — — Cancelled/Forfeited (3,889 ) 112.30 Options outstanding December 31, 2015 44,379 $ 96.40 Granted 88,892 16.60 Exercised — — Cancelled/Forfeited (15,149 ) 57.20 Options Outstanding December 31, 2016 118,122 $ 41.40 Granted — — Exercised — — Cancelled/Forfeited (31,791 ) 72.60 Options Outstanding December 31, 2017 86,331 $ 29.90 4.7 $ — Options Exercisable December 31, 2017 32,746 $ 45.30 4.2 $ —
Assumptions Used to Estimate Fair Value of Options Granted	The assumptions used to estimate the fair value of options granted during the years ended December 31, 2017 and 2016 are as follows: Year Ended December 31, 2017 2016 Expected dividend yield 0% 0% Expected stock price volatility 87.8% - 96.5% 87.8% - 96.5% Risk-free interest rate 1.1% - 1.5% 1.1% - 1.5% Expected life of options (years) 4 - 5 4 - 5
Summary of Issued and Outstanding Stock Options	A summary of the status of our issued and outstanding stock options as of December 31, 2017 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 12/31/17 Weighted-Average Exercise Price Number Exercisable At 12/31/17 Weighted-Average Exercise Price $ 9.70 2,750 $ 9.70 919 $ 9.70 $ 16.90 67,294 $ 16.90 22,873 $ 16.90 $ 40.50 4,000 $ 40.50 — $ — $ 49.00 4,000 $ 49.00 667 $ 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 86,331 $ 29.90 32,746 $ 45.30
Percentage of Awards to Vest	The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule: TSR Rank Percentage of Awards to Vest 1-3 100 % 4-6 75 % 7-10 50 % 11-13 25 % 14-16 0 %
Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock	Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions: Year Ended December 31, 2015 Expected Dividend Yield 0.0 % Risk-Free Interest Rate 1.0 % Expected Volatility – Rex Energy 58.6 % Expected Volatility – Peer Group 29.8%-85.0% Market Index 35.6 % Expected Life Three Years
Summary of Nonvested Restricted Stock Activity	A summary of the restricted stock activity for the years ended December 31, 2017, 2016 and 2015 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2014 152,005 $ 140.50 Awards 223,684 33.50 Vested (60,636 ) 93.90 Forfeitures (67,037 ) 113.30 Restricted stock awards, as of December 31, 2015 248,016 $ 62.70 Awards 142,309 9.10 Vested (87,206 ) 73.30 Forfeitures (60,295 ) 67.30 Restricted stock awards, as of December 31, 2016 242,824 $ 26.30 Awards 101,237 5.18 Vested (102,351 ) 21.52 Forfeitures (41,235 ) 48.17 Restricted stock awards, as of December 31, 2017 200,475 $ 13.62

Suspended Exploratory Well Co43

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Net Change in Capitalized Exploratory Well Costs	The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for each of the years ended December 31, 2017, 2016 and 2015 ($ in thousands): 2017 2016 2015 Beginning Balance at January 1, $ 17,201 $ 16,970 $ 22,573 Additions to capitalized exploratory well costs pending the determination of estimated proved reserves 91,166 46,759 144,333 Divested wells (31 ) — — Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves (107,883 ) (39,126 ) (147,054 ) Capitalized exploratory well costs charged to expense — (7,402 ) (2,882 ) Ending Balance at December 31, 453 17,201 16,970 Less exploratory well costs that have been capitalized for a period of one year or less (453 ) (17,201 ) (12,049 ) Capitalized exploratory well costs for a period of greater than one year $ — $ — $ 4,921 Number of projects that have exploratory well costs capitalized for a period of more than one year — — 13

Costs Incurred In Oil And Nat44

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Costs Incurred in Oil and Natural Gas Property Acquisitions and Development	Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands): 2017 2016 2015 Consolidated Entities: Acquisition of Properties Proved $ — $ — $ — Unproved 3,805 6,671 27,933 Exploration Costs(a) 90,700 24,650 157,067 Development Costs(a) 45,983 11,166 17,336 Subtotal 140,488 42,487 202,336 Asset Retirement Obligations 797 1,927 2,739 Total Costs Incurred $ 141,285 $ 44,414 $ 205,075 Share of Equity Method Investments: Acquisition of Properties Proved $ — $ — $ — Unproved — — — Exploration Costs — — — Development Costs(a) 800 793 824 Total $ 800 $ 793 $ 824 (a) Includes Depreciation expense for support equipment and facilities
Reconciliation of Total Costs Incurred for Consolidated Entities to Reported Capital Expenditures	The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands): 2017 2016 2015 Total Costs Incurred by Consolidated Entities $ 141,285 $ 44,414 $ 205,075 Illinois Basin Expenditures — — 15,405 Exploration Expense (527 ) (2,178 ) (2,617 ) Asset Retirement Obligations (797 ) (1,927 ) (2,739 ) Depreciation for Support Equipment and Facilities (2,170 ) — (4,905 ) Corporate Expenditures 416 — 231 Other (a) 87 — (16,522 ) Total Capital Expenditures $ 138,294 $ 40,309 $ 193,928 (a) Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and BSP and intercompany capital transactions.

Oil And Natural Gas Capitaliz45

Oil And Natural Gas Capitalized Costs (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Capitalized Costs for Natural Gas and Oil Production Activities	Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands): 2017 2016 Consolidated Entities: Proven Oil and Natural Gas Properties $ 1,086,625 $ 1,055,467 Pipelines and Support Equipment 18,902 21,088 Field Operation Vehicles and Other Equipment 9,586 11,239 Wells and Facilities in Progress 38,660 21,964 Unproven Properties 186,523 215,794 Total 1,340,296 1,325,552 Less Accumulated Depreciation and Depletion (459,652 ) (474,046 ) Total $ 880,644 $ 851,506 Share of Equity Method Investments: Pipelines and Support Equipment 19,963 19,962 Wells and Facilities in Progress — — Total 19,963 19,962 Less Accumulated Depreciation and Depletion (5,011 ) (4,211 ) Total $ 14,952 $ 15,751

Oil and Natural Gas Reserve Q46

Oil and Natural Gas Reserve Quantities (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells	Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2017, 2016 and 2015. We accounted for the estimated proved reserves of our Illinois Basin assets as a sale in 2016. Prior years were not retroactively adjusted for the effect of discontinued operations. 2017 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 1,866.0 44,824.4 367,640.9 647,783.1 Extensions, Discoveries and Additions 1,929.6 22,295.2 164,222.7 309,571.7 Revisions of Previous Estimates 90.0 10,225.7 103,278.3 165,172.5 Sales of Reserves (144.5 ) (984.4 ) (14,790.4 ) (21,563.8 ) Production (271.8 ) (4,079.1 ) (41,972.0 ) (68,077.4 ) Estimated Proved Reserves-End of Period 3,469.3 72,281.8 578,379.5 1,032,886.1 2016 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 5,317.1 40,346.6 406,462.8 680,445.0 Extensions, Discoveries and Additions 373.5 2,183.7 11,084.6 26,427.8 Revisions of Previous Estimates 323.9 8,262.0 7,629.3 59,144.7 Sales of Reserves (3,788.1 ) (1,860.5 ) (12,917.7 ) (46,809.5 ) Production (360.4 ) (4,107.4 ) (44,618.1 ) (71,424.9 ) Estimated Proved Reserves-End of Period 1,866.0 44,824.4 367,640.9 647,783.1 2015 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 Extensions, Discoveries and Additions 949.0 10,079.3 76,816.9 142,986.7 Revisions of Previous Estimates (4,176.8 ) (38,249.7 ) (448,461.3 ) (703,020.3 ) Purchases (7.7 ) (1,389.6 ) (16,471.1 ) (24,854.9 ) Production (1,132.1 ) (3,345.9 ) (44,606.8 ) (71,474.8 ) Estimated Proved Reserves-End of Period 5,317.1 40,346.6 406,462.8 680,445.0 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Proved Developed Reserves December 31, 2017 2,235.4 64,738.5 519,118.6 920,962.0 December 31, 2016 1,865.9 44,824.4 367,641.3 647,783.1 December 31, 2015 4,944.6 37,941.9 389,754.4 647,073.4 Proved Undeveloped Reserves December 31, 2017 1,233.9 7,543.3 59,260.9 111,923.9 December 31, 2016 - - - - December 31, 2015 372.5 2,404.7 16,708.4 33,371.6

Standardized Measure Of Disco47

Standardized Measure Of Discounted Future Net Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves	The following summary sets forth our future net cash flows relating to proven oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2017, 2016 and 2015 ($ in thousands): 2017 2016 2015 Future Cash Inflows $ 2,952,274 (a) $ 1,371,210 (b) $ 1,716,131 (c) Future Costs: Production (1,721,109 ) (1,061,275 ) (1,144,049 ) Abandonment (9,866 ) (47,159 ) (143,459 ) Development (45,365 ) — (18,952 ) Net Future Cash Inflow Before Income Taxes 1,175,934 262,776 409,671 Future Income Tax Expense (24,105 ) — — Total Future Net Cash Flows Before 10.0% Discount 1,151,829 262,776 409,671 Less: Effect of 10.0% Discount Factor (644,810 ) (97,179 ) (154,048 ) Standardized Measure of Discounted Future Net Cash Flows $ 507,019 $ 165,597 $ 255,623 (a) Calculated using weighted average prices of $2.793 per Mcf, $45.62 per barrel of oil and $16.31 per barrel of NGLs (b) Calculated using weighted average prices of $2.264 per Mcf, $36.68 per barrel of oil and $10.50 per barrel of NGLs (c) Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows	The principal sources of change in the standardized measure of discounted future net cash flows are as follows: 2017 2016 2015 Standardized Measure – Beginning of Period $ 165,597 $ 255,623 $ 1,025,364 Revisions of Previous Estimates: Changes in Prices and Production Costs 137,000 (89,583 ) (1,296,866 ) Revisions in Quantities 78,276 9,851 (270,673 ) Changes in Future Development Costs (41,803 ) 7,786 595,547 Accretion of Discount and Timing of Future Cash Flows 16,560 25,562 116,514 Net Change in Income Tax (24,105 ) — 139,776 Purchase (Sale) of Reserves in Place (6,692 ) (54,598 ) (37,101 ) Plus Extensions, Discoveries, and Other Additions 166,867 21,841 88,152 Development Costs Incurred 45,983 11,166 31,574 Sales of Product – Net of Production Costs (84,452 ) (34,301 ) (52,952 ) Changes in Timing and Other 53,788 12,250 (83,712 ) Standardized Measure – End of Period $ 507,019 $ 165,597 $ 255,623

Results Of Operations For Oil48

Results Of Operations For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Results of Operations	Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation): 2017 2016 2015 Consolidated Entities (in thousands): Revenues Oil and Natural Gas Sales $ 205,266 $ 139,017 $ 138,749 Expenses Production and Lease Operating Expense 120,794 104,699 93,892 Impairment Expense 21,383 74,619 283,244 Exploration Expense 527 2,178 2,617 Depletion, Depreciation, Amortization and Accretion 59,028 62,874 85,844 Total Costs 201,732 244,370 465,597 Pre-Tax Operating Income (Loss) 3,534 (105,353 ) (326,848 ) Income Tax Benefit (Expense) (a) 144 (1,317 ) (5,687 ) Results of Operations for Oil and Gas Producing Activities $ 3,678 $ (106,670 ) $ (332,535 ) Share of Equity Method Investments (in thousands): Expenses Depletion, Depreciation, Amortization and Accretion $ 813 $ 813 $ 812 Total Costs 813 813 812 Pre-Tax Operating Loss (813 ) (813 ) (812 ) Income Tax Expense (a) (33 ) (10 ) (14 ) Results of Operations for Oil and Gas Producing Activities $ (846 ) $ (823 ) $ (826 ) Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities $ 2,832 $ (107,493 ) $ (333,361 ) (a) Computed using the effective rate for continuing operations for each period: 4.07% in 2017; -1.25% in 2016 and; -1.74% in 2015.

Selected Quarterly Financial 49

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Unaudited Financial Information on Quarterly Basis	The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. REX ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ and Shares in Thousands Except per Share Data) 2017 March June September December Revenues $ 52,071 $ 47,462 $ 47,975 $ 57,758 Impairment Expense 1,546 3,032 11,877 4,928 Other Costs and Expenses 47,842 54,033 82,632 63,618 Net Income (Loss) Attributable to Rex Energy 2,683 (9,603 ) (46,534 ) (10,788 ) Preferred Stock Dividends (598 ) (598 ) (598 ) (598 ) Net Income (Loss) Attributable to Common Shareholders $ 2,085 $ (10,201 ) $ (47,132 ) $ (11,386 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Income (Loss) $ 0.21 $ (1.03 ) $ (4.76 ) $ (1.13 ) Basic — Weighted Average Shares Outstanding 9,769 9,881 9,906 10,049 Diluted — Net Income (Loss) $ 0.21 $ (1.03 ) $ (4.76 ) $ (1.13 ) Diluted — Weighted Average Shares Outstanding 9,769 9,881 9,906 10,049 2016 March June September December Revenues $ 25,686 $ 31,265 $ 34,039 $ 48,027 Impairment Expense 10,641 25,136 9,563 29,279 Other Costs and Expenses 67,696 59,040 40,953 94,346 Net Loss From Continuing Operations (52,651 ) (52,911 ) (16,477 ) (75,598 ) Net Income (Loss) From Discontinued Operations, Net of Income Taxes (7,490 ) (1,683 ) 21,892 8,203 Net Income (Loss) Attributable to Rex Energy (60,141 ) (54,594 ) 5,415 (67,395 ) Preferred Stock Dividends (2,105 ) (1,723 ) (613 ) (650 ) Effect of Preferred Stock Conversions — 72,316 — 668 Net Income (Loss) Attributable to Common Shareholders $ (62,246 ) $ 15,999 $ 4,802 $ (67,377 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic — Continuing Operations $ (9.78 ) $ 2.45 $ (1.89 ) $ (7.77 ) Basic — Discontinued Operations (1.34 ) (0.23 ) 2.41 0.84 Basic — Net Income (Loss) $ (11.12 ) $ 2.22 $ 0.52 $ (6.93 ) Basic — Weighted Average Shares Outstanding 5,600 7,180 9,080 9,740 Diluted — Continuing Operations $ (9.78 ) $ 2.45 $ (1.89 ) $ (7.77 ) Diluted — Discontinued Operations (1.34 ) (0.23 ) 2.41 0.84 Diluted — Net Income (Loss) $ (11.12 ) $ 2.22 $ 0.52 $ (6.93 ) Diluted — Weighted Average Shares Outstanding 5,600 7,180 9,080 9,740

Condensed Consolidating Finan50

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2017 ($ in Thousands, Except Share and Per Share Data) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 15,244 $ — $ 3 $ — $ 15,247 Accounts Receivable 25,974 — — — 25,974 Taxes Receivable — — 2,049 — 2,049 Short-Term Derivative Instruments 8,008 — — — 8,008 Inventory, Prepaid Expenses and Other 2,106 — 2,508 — 4,614 Total Current Assets 51,332 — 4,560 — 55,892 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,086,625 — — — 1,086,625 Unevaluated Oil and Gas Properties 186,523 — — — 186,523 Other Property and Equipment 19,640 — — — 19,640 Wells and Facilities in Progress 38,660 — — — 38,660 Pipelines 16,803 — — — 16,803 Total Property and Equipment 1,348,251 — — — 1,348,251 Less: Accumulated Depreciation, Depletion and Amortization (463,899 ) — — — (463,899 ) Net Property and Equipment 884,352 — — — 884,352 Other Assets 44 — — — 44 Intercompany Receivables — — 1,072,637 (1,072,637 ) — Investment in Subsidiaries – Net (2,484 ) — (272,261 ) 274,745 — Long-Term Derivative Instruments (2 ) — 1,721 — 1,719 Deferred Tax Assets - Long-Term — — 130 — 130 Total Assets $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 62,354 $ — $ — $ — $ 62,354 Current Maturities of Long-Term Debt 1,926 — 832,399 — 834,325 Accrued Liabilities 32,214 — 13,004 — 45,218 Short-Term Derivative Instruments 14,892 — — — 14,892 Total Current Liabilities 111,386 — 845,403 — 956,789 Long-Term Derivative Instruments 14,249 — — — 14,249 Long-Term Debt — — — — — Other Long-Term Debt 8,156 — — — 8,156 Other Deposits and Liabilities 7,153 — — — 7,153 Future Abandonment Cost 9,352 — — — 9,352 Intercompany Payables 1,068,231 4,406 — (1,072,637 ) — Total Liabilities 1,218,527 4,406 845,403 (1,072,637 ) 995,699 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 652,917 (177,144 ) 652,917 Accumulated Deficit (462,429 ) (4,406 ) (691,544 ) 451,889 (706,490 ) Total Stockholders’ Equity (285,285 ) (4,406 ) (38,616 ) 274,745 (53,562 ) Total Liabilities and Stockholders’ Equity $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2016 ($ in Thousands, Except Share and Per Share Data) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 3,694 $ — $ 3 $ — $ 3,697 Accounts Receivable 22,609 — 2,839 — 25,448 Taxes Receivable — — 211 — 211 Short-Term Derivative Instruments 1,873 — — — 1,873 Inventory, Prepaid Expenses and Other 2,521 — 25 — 2,546 Total Current Assets 30,697 — 3,078 — 33,775 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,053,461 — — — 1,053,461 Unevaluated Oil and Gas Properties 215,794 — — — 215,794 Other Property and Equipment 21,401 — — — 21,401 Wells and Facilities in Progress 21,964 — — — 21,964 Pipelines 18,029 — — — 18,029 Total Property and Equipment 1,330,649 — — — 1,330,649 Less: Accumulated Depreciation, Depletion and Amortization (475,205 ) — — — (475,205 ) Net Property and Equipment 855,444 — — — 855,444 Deferred Financing Costs and Other Assets—Net 2,492 — — — 2,492 Intercompany Receivables — — 1,035,713 (1,035,713 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments (723 ) — 2,935 — 2,212 Total Assets $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 40,712 $ — $ — $ — $ 40,712 Current Maturities of Long-Term Debt 764 — — — 764 Accrued Liabilities 32,328 421 4,458 — 37,207 Short-Term Derivative Instruments 25,025 — — — 25,025 Total Current Liabilities 98,829 421 4,458 — 103,708 Long-Term Derivative Instruments 7,227 — — — 7,227 Long-Term Debt — — 751,946 — 751,946 Other Long-Term Debt 3,409 — — — 3,409 Other Deposits and Liabilities 8,671 — — — 8,671 Future Abandonment Cost 8,736 — 8,736 Intercompany Payables 1,032,050 3,663 — (1,035,713 ) — Total Liabilities 1,158,922 4,084 756,404 (1,035,713 ) 883,697 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 650,669 (177,144 ) 650,669 Accumulated Deficit (450,544 ) (4,084 ) (493,332 ) 307,506 (640,454 ) Total Stockholders’ Equity (273,400 ) (4,084 ) 157,348 130,362 10,226 Total Liabilities and Stockholders’ Equity $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923
Condensed Consolidating Statements of Operations	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 205,246 $ — $ — $ — $ 205,246 Other Revenue 20 — — — 20 TOTAL OPERATING REVENUE 205,266 — — — 205,266 OPERATING EXPENSES Production and Lease Operating Expense 120,794 — — — 120,794 General and Administrative Expense 16,601 — 1,257 — 17,858 Gain on Disposal of Assets (1,428 ) — — — (1,428 ) Impairment Expense 21,383 — — — 21,383 Exploration Expense 527 — — — 527 Depreciation, Depletion, Amortization and Accretion 58,713 315 — — 59,028 Other Operating Expense 611 — — — 611 TOTAL OPERATING EXPENSES 217,201 315 1,257 — 218,773 LOSS FROM OPERATIONS (11,935 ) (315 ) (1,257 ) — (13,507 ) OTHER INCOME (EXPENSE) Interest Expense (2,288 ) — (46,538 ) — (48,826 ) Loss on Derivatives, Net (131 ) — (1,216 ) — (1,347 ) Other Income (Expense) (270 ) (7 ) 16 — (261 ) Loss on Extinguishment of Debt — — (3,029 ) — (3,029 ) Loss From Equity in Consolidated Subsidiaries (309 ) — (14,337 ) 14,646 — TOTAL OTHER INCOME (EXPENSE) (2,998 ) (7 ) (65,104 ) 14,646 (53,463 ) LOSS BEFORE INCOME TAX (14,933 ) (322 ) (66,361 ) 14,646 (66,970 ) Income Tax (Expense) Benefit 596 13 2,119 — 2,728 NET LOSS (14,337 ) (309 ) (64,242 ) 14,646 (64,242 ) Preferred Stock Dividends — — (2,392 ) — (2,392 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (14,337 ) $ (309 ) $ (66,634 ) $ 14,646 $ (66,634 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 139,000 $ — $ — $ — $ 139,000 Other Revenue 17 — — — 17 TOTAL OPERATING REVENUE 139,017 — — — 139,017 OPERATING EXPENSES Production and Lease Operating Expense 104,699 — — — 104,699 General and Administrative Expense 17,488 5 3,128 — 20,621 Gain on Disposal of Assets (4,121 ) — — — (4,121 ) Impairment Expense 74,624 (5 ) — — 74,619 Exploration Expense 2,177 1 — — 2,178 Depreciation, Depletion, Amortization and Accretion 62,849 25 — — 62,874 Other Operating Expense 10,754 — — — 10,754 TOTAL OPERATING EXPENSES 268,470 26 3,128 — 271,624 LOSS FROM OPERATIONS (129,453 ) (26 ) (3,128 ) — (132,607 ) OTHER INCOME (EXPENSE) Interest Expense (1,326 ) — (42,193 ) — (43,519 ) Gain (Loss) on Derivatives, Net (34,285 ) — 1,770 — (32,515 ) Other Income (Expense) 41 — (2,165 ) — (2,124 ) Debt Exchange Expense — — (9,063 ) — (9,063 ) Gain on Extinguishment of Debt — 24,627 — 24,627 Income (Loss) From Equity in Consolidated Subsidiaries (94 ) 94 (146,344 ) 146,344 — TOTAL OTHER INCOME (EXPENSE) (35,664 ) 94 (173,368 ) 146,344 (62,594 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (165,117 ) 68 (176,496 ) 146,344 (195,201 ) Income Tax Expense (2,060 ) — (376 ) — (2,436 ) NET INCOME (LOSS) FROM CONTINUING OPERATIONS (167,177 ) 68 (176,872 ) 146,344 (197,637 ) Income (Loss) From Discontinued Operations, Net of Income Tax 20,887 (122 ) 157 20,922 NET LOSS (146,290 ) (54 ) (176,715 ) 146,344 (176,715 ) Preferred Stock Dividends — — (5,091 ) — (5,091 ) Effect of Preferred Stock Conversion — — 72,984 — 72,984 NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (146,290 ) $ (54 ) $ (108,822 ) $ 146,344 $ (108,822 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 138,707 $ — $ — $ — $ 138,707 Other Revenue 42 — — — 42 TOTAL OPERATING REVENUE 138,749 — — — 138,749 OPERATING EXPENSES Production and Lease Operating Expense 93,892 — — — 93,892 General and Administrative Expense 20,849 — 5,845 — 26,694 Gain on Disposal of Assets (540 ) — — — (540 ) Impairment Expense 282,833 411 — — 283,244 Exploration Expense 2,616 1 — — 2,617 Depreciation, Depletion, Amortization and Accretion 85,839 5 — — 85,844 Other Operating Expense 5,603 — — — 5,603 TOTAL OPERATING EXPENSES 491,092 417 5,845 — 497,354 LOSS FROM OPERATIONS (352,343 ) (417 ) (5,845 ) — (358,605 ) OTHER INCOME (EXPENSE) Interest Expense (248 ) — (47,535 ) — (47,783 ) Gain on Derivatives, Net 59,242 — 934 — 60,176 Other Expense (129 ) — — — (129 ) Loss From Equity Method Investments (411 ) — — — (411 ) Income (Loss) From Equity in Consolidated Subsidiaries (429 ) 429 (309,250 ) 309,250 — TOTAL OTHER INCOME (EXPENSE) 58,025 429 (355,851 ) 309,250 11,853 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (294,318 ) 12 (361,696 ) 309,250 (346,752 ) Income Tax Expense (5,111 ) (7 ) (912 ) — (6,030 ) NET INCOME (LOSS) FROM CONTINUING OPERATIONS (299,429 ) 5 (362,608 ) 309,250 (352,782 ) Income (Loss) From Discontinued Operations, Net of Income Taxes (45,546 ) 37,965 (670 ) — (8,251 ) NET INCOME (LOSS) (344,975 ) 37,970 (363,278 ) 309,250 (361,033 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 2,245 — — 2,245 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY (344,975 ) 35,725 (363,278 ) 309,250 (363,278 ) Preferred Stock Dividends — — (9,660 ) — (9,660 ) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (344,975 ) $ 35,725 $ (372,938 ) $ 309,250 $ (372,938 )
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Loss $ (14,337 ) $ (309 ) $ (64,242 ) $ 14,646 $ (64,242 ) Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities Depreciation, Depletion, Amortization and Accretion 58,713 315 — — 59,028 Loss on Derivatives 131 — 1,216 — 1,347 Cash Settlements of Derivatives (10,100 ) — — — (10,100 ) Non-Cash Dry Hole Expense 13 — — — 13 Equity-based Compensation Expense (1 ) — 1,232 — 1,231 Impairment Expense 21,383 — — — 21,383 Amortization of Debt Issue Costs — — 1,165 — 1,165 Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 14,063 — 14,063 Loss on Extinguishment of Debt — — 3,029 — 3,029 Gain on Sale of Assets (1,428 ) — — — (1,428 ) Deferred Income Tax Benefit — — (130 ) — (130 ) Other Non-cash Expenses 471 — — — 471 Changes in operating assets and liabilities Accounts Receivable 5,261 — (3 ) — 5,258 Taxes Receivable — — (1,839 ) — (1,839 ) Inventory, Prepaid Expenses and Other Assets (1,159 ) — (901 ) — (2,060 ) Accounts Payable and Accrued Liabilities 6,000 — 8,558 — 14,558 Other Assets and Liabilities (3,210 ) — (49 ) — (3,259 ) NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES 61,737 6 (37,901 ) 14,646 38,488 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 36,631 (6 ) (21,979 ) (14,646 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 31,704 — — — 31,704 Acquisitions of Undeveloped Acreage (3,805 ) — — — (3,805 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (113,411 ) — — — (113,411 ) NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES (48,881 ) (6 ) (21,979 ) (14,646 ) (85,512 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 217,000 — 217,000 Repayments of Long-Term Debt and Lines of Credit — — (145,170 ) — (145,170 ) Repayments of Loans and Other Notes Payable (1,306 ) — — — (1,306 ) Debt Issuance Costs — — (10,754 ) — (10,754 ) Dividends Paid on Preferred Stock — — (1,196 ) — (1,196 ) NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (1,306 ) — 59,880 — 58,574 NET INCREASE IN CASH 11,550 0 (0 ) 0 11,550 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 15,244 $ 0 $ 3 $ 0 $ 15,247 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Loss $ (146,290 ) $ (54 ) $ (176,715 ) $ 146,344 $ (176,715 ) Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities Depreciation, Depletion, Amortization and Accretion 67,915 60 — — 67,975 Gain (Loss) on Derivatives 34,285 — (1,770 ) — 32,515 Cash Settlements of Derivatives 32,571 — — — 32,571 Non-Cash Dry Hole Expense 905 — — — 905 Equity-based Compensation Expense 40 — 2,919 — 2,959 Impairment Expense 78,160 2 78,162 (78,162 ) 78,162 Amortization of Debt Issuance Costs — — 1,640 — 1,640 Amortization of Bond Discounts and Premiums — — (100 ) — (100 ) Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 19,603 — 19,603 Gain on Extinguishment of Debt — — (24,627 ) — (24,627 ) (Gain) Loss on Sale of Assets (34,697 ) 46 — — (34,651 ) Other Non-cash (Income) Expense (208 ) — 230 — 22 Changes in operating assets and liabilities Accounts Receivable (44,354 ) (863 ) 38,803 — (6,414 ) Inventory, Prepaid Expenses and Other Assets 906 — — — 906 Accounts Payable and Accrued Liabilities 8,815 — (6,020 ) — 2,795 Other Assets and Liabilities (1,953 ) 3 — — (1,950 ) NET CASH USED BY OPERATING ACTIVITIES (3,905 ) (806 ) (67,875 ) 68,182 (4,404 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 3,587 (94 ) 64,689 (68,182 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 39,904 980 — — 40,884 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (6,671 ) (41 ) — — (6,712 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (48,943 ) (39 ) — — (48,982 ) NET CASH PROVIDED BY INVESTING ACTIVITIES 7,338 806 64,689 (68,182 ) 4,651 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 71,400 — 71,400 Repayments of Long-Term Debt and Lines of Credit — — (65,230 ) — (65,230 ) Repayments of Loans and Other Notes Payable (828 ) — — — (828 ) Debt Issuance Costs — — (2,983 ) — (2,983 ) NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (828 ) — 3,187 — 2,359 NET INCREASE IN CASH 2,605 0 1 — 2,606 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 3,694 $ 0 $ 3 $ — $ 3,697 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (344,975 ) $ 37,970 $ (363,278 ) $ 309,250 $ (361,033 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities Loss on Equity Method Investments 411 — — — 411 Depreciation, Depletion, Amortization and Accretion 105,555 3,230 — (3,963 ) 104,822 Gain on Derivatives (59,242 ) — (934 ) — (60,176 ) Cash Settlements of Derivatives 54,859 — 934 — 55,793 Non-Cash Dry Hole Expense 199 136 — (5 ) 330 Equity-based Compensation Expense 99 — 6,450 — 6,549 Impairment Expense 345,892 1,396 345,892 (347,405 ) 345,775 Amortization of Debt Issuance Costs 17 13 2,015 — 2,045 Amortization of Bond Discounts and Premiums — — (381 ) — (381 ) Gain on Sale of Assets (477 ) (44 ) — — (521 ) Gain on Sale of Water Solutions — — (57,778 ) — (57,778 ) Other Non-cash Income (Expense) (218 ) (346 ) — — (564 ) Changes in operating assets and liabilities Accounts Receivable 24,240 (453 ) 429 (2,537 ) 21,679 Inventory, Prepaid Expenses and Other Assets (431 ) (142 ) 5 — (568 ) Accounts Payable and Accrued Liabilities (20,008 ) (4,969 ) (515 ) 2,537 (22,955 ) Other Assets and Liabilities (2,497 ) (73 ) 27 — (2,543 ) NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES 103,424 36,718 (67,134 ) (42,123 ) 30,885 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 96,664 (37,425 ) (100,198 ) 40,959 — Proceeds from Joint Venture Acreage Management 58 — — — 58 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 9,766 560 66,900 — 77,226 Proceeds from Joint Venture 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (27,963 ) (279 ) — — (28,242 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (214,450 ) (7,813 ) — 1,164 (221,099 ) NET CASH PROVIDED USED BY INVESTING ACTIVITIES (119,314 ) (44,957 ) (33,298 ) 42,123 (155,446 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 35,814 193,500 — 229,314 Repayments of Long-Term Debt and Lines of Credit — (26,335 ) (82,000 ) — (108,335 ) Repayments of Loans and Other Notes Payable (999 ) (520 ) — — (1,519 ) Debt Issuance Costs — (3 ) (1,411 ) — (1,414 ) Distribution by the Partners of Consolidated Subsidiary — (830 ) — — (830 ) Dividends Paid on Preferred Stock — — (9,660 ) — (9,660 ) NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (999 ) 8,126 100,429 — 107,556 NET DECREASE IN CASH (16,889 ) (113 ) (3 ) — (17,005 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH - ENDING $ 1,089 $ (0 ) $ 2 $ — $ 1,091

Basis of Presentation and Pri51

Basis of Presentation and Principles of Consolidation - Additional Information (Details) $ in Millions	May 12, 2017shares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Mar. 31, 2017shares	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Outstanding Indebtedness		$ 789.8
Reverse stock split		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.
Common Stock, shares issued | shares	9,900,000	10,244,394	9,787,146	99,000,000
Water Solutions Holdings, LLC
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Ownership percentage by parent					60.00%
Illinois Basin Operations
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Closed date of sale		Aug. 31, 2016
Effective date of sale		Jul. 1, 2016
Fair value of contingent consideration derivative asset		$ 1.7	$ 2.9
Common Stock
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Reverse stock split	one-for-ten
Stockholders' equity, reverse stock split ratio	0.1

Summary of Significant Accoun52

Summary of Significant Accounting Policies - Additional Information (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017USD ($)shares	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)shares	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)Customershares	Dec. 31, 2016USD ($)Customershares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014shares
Accounting Policies [Line Items]
Allowance for bad debts	$ 100				$ 100				$ 100	$ 100
Accounts Receivable	25,974				25,448				$ 25,974	$ 25,448
Number of customers | Customer									3	3
Capitalized interest costs									$ 1,700	$ 2,700	$ 7,700
Impairment Expense	4,928	$ 11,877	$ 3,032	$ 1,546	29,279	$ 9,563	$ 25,136	$ 10,641	21,383	74,619	283,244
Accretion expense									1,915	985	1,000
Increase in estimated present value of asset retirement obligations									834	1,918
Future Abandonment Costs	$ 9,939				$ 9,865				$ 9,939	$ 9,865	$ 11,934
Income tax examination minimum likelihood of tax benefits being realized upon ultimate settlement									50.00%
Common Stock, shares outstanding | shares	10,244,394				9,787,146				10,244,394	9,787,146
Options outstanding | shares	86,331				118,122				86,331	118,122	44,379	40,268
Stock Appreciation Rights (SARs)
Accounting Policies [Line Items]
Other than Options outstanding | shares	2,050								2,050
Restricted Stock
Accounting Policies [Line Items]
Other than Options outstanding | shares	200,475				242,824				200,475	242,824	248,016	152,005
Performance Shares
Accounting Policies [Line Items]
Other than Options outstanding | shares	38,261								38,261
Warrants
Accounting Policies [Line Items]
Share based compensation, warrants outstanding | shares	0								0
Accrued Liabilities
Accounting Policies [Line Items]
Future Abandonment Costs	$ 600				$ 1,100				$ 600	$ 1,100
Minimum
Accounting Policies [Line Items]
Service properties, equipment and other assets, estimated useful lives									3 years
Payment period for condensate and natural gas purchases after end of each production month									30 days
Maximum
Accounting Policies [Line Items]
Service properties, equipment and other assets, estimated useful lives									40 years
Payment period for condensate and natural gas purchases after end of each production month									60 days
Sumitomo Corporation, Benefit Street Partners, LLC and ArcLight Capital Partners, LLC.
Accounting Policies [Line Items]
Receivable from related party	2,500				2,700				$ 2,500	2,700
Condensate And Gas Production
Accounting Policies [Line Items]
Accounts Receivable	22,900				22,200				22,900	22,200
Condensate And Gas Production | Major Customers
Accounting Policies [Line Items]
Accounts Receivable	$ 19,300				$ 17,500				$ 19,300	$ 17,500

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$ 9,865	$ 11,934
Asset Retirement Obligation Incurred	1,061	575
Asset Retirement Obligation Settled	(3,187)	(671)
Asset Retirement Obligation Cancelled or Sold Properties	(549)	(4,876)
Asset Retirement Obligation Revision of Estimated Obligation	834	1,918
Asset Retirement Obligation Accretion Expense	1,915	985	$ 1,000
Total Future Abandonment Costs	$ 9,939	$ 9,865	$ 11,934

Business and Oil and Gas Prop54

Business and Oil and Gas Property Acquisitions and Dispositions - Additional Information (Details)

Jan. 11, 2017USD ($)aMMcfeWell

Aug. 18, 2016USD ($)

Jun. 14, 2016USD ($)

May 20, 2016USD ($)Well

Mar. 01, 2016Well

Mar. 31, 2015USD ($)Well

Jan. 31, 2017USD ($)

Jul. 31, 2015USD ($)

Jun. 30, 2016USD ($)

Dec. 31, 2017USD ($)aWellQuarterlyInstallmentbbl

Dec. 31, 2015USD ($)

Jun. 30, 2015USD ($)

Dec. 31, 2014

Business Acquisition And Dispositions [Line Items]

Gain loss on sale of assets

$ 57,778,000

Sale of Warrior South Assets

Business Acquisition And Dispositions [Line Items]

Total consideration for the transaction

$ 29,100,000

Net proceeds from sale of property

24,100,000

Gain loss on sale of assets

$ 1,800,000

Amount held in escrow

$ 5,000,000

$ 5,000,000

Number of gross wells | Well

14

Production unit of natural gas | MMcfe

9

Net acres sold | a

4,100

Sale of Warrior South Assets | Rex, MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc.

Business Acquisition And Dispositions [Line Items]

Total consideration for the transaction

$ 50,000,000

Production unit of natural gas | MMcfe

15

Net acres sold | a

6,200

Water Solutions [Member]

Business Acquisition And Dispositions [Line Items]

Ownership percentage by parent

60.00%

Total consideration for the transaction

$ 130,000,000

Net proceeds from sale of property

$ 66,800,000

Gain loss on sale of assets

$ 57,600,000

Arc Light Capital Partners Limited Liability Corporation

Business Acquisition And Dispositions [Line Items]

Percentage of estimated well costs

35.00%

Total consideration for the transaction

$ 67,600,000

Amount received at closing of wells

$ 16,600,000

Percentage of working interest attained through return on investment and internal rate of return

50.00%

Percentage of working interest

35.00%

Percentage of remaining working interest

17.50%

Arc Light Capital Partners Limited Liability Corporation | Butler County, Pennsylvania

Business Acquisition And Dispositions [Line Items]

Number of specifically designated wells for development | Well

32

Benefit Street Partners Limited Liability Corporation

Business Acquisition And Dispositions [Line Items]

Percentage of working interest

65.00%

Amount received for working interest in wells by partners

$ 134,000,000

Number of wells in which BSP Options to Participate in development | Well

36

Number of producing wells | Well

45

Number of wells committed for line and producing | Well

45

Benefit Street Partners Limited Liability Corporation | Maximum

Business Acquisition And Dispositions [Line Items]

Total consideration for the transaction

$ 175,000,000

Percentage of working interest earned in acreage

20.00%

Benefit Street Partners Limited Liability Corporation | Minimum

Business Acquisition And Dispositions [Line Items]

Percentage of working interest earned in acreage

15.00%

Benefit Street Partners Limited Liability Corporation | Butler County, Pennsylvania

Business Acquisition And Dispositions [Line Items]

Number of specifically designated wells for development | Well

16

Percentage of estimated well costs

15.00%

Number of drilled and completed wells to be placed into service | Well

16

Benefit Street Partners Limited Liability Corporation | Moraine East and Warrior North

Business Acquisition And Dispositions [Line Items]

Number of specifically designated wells for development | Well

58

Benefit Street Partners Limited Liability Corporation | Warrior North Ohio

Business Acquisition And Dispositions [Line Items]

Number of specifically designated wells for development | Well

6

Percentage of estimated well costs

65.00%

Number of drilled and completed wells to be placed into service | Well

6

Diversified Oil and Gas LLC

Business Acquisition And Dispositions [Line Items]

Net proceeds from sale of property

$ 100,000

Number of wells sold including pipelines and support equipment | Well

300

Gain on disposition of oil and gas property

$ 4,600,000

Uncollectible accounts receivable written off

$ 200,000

Illinois Basin Operations | Discontinued Operations Assets Held For Sale

Business Acquisition And Dispositions [Line Items]

Net proceeds from sale of property

$ 38,500,000

Received purchase from deposits

$ 2,500,000

Proceeds receivable quarterly installments.

$ 900,000

Proceeds receivable quarterly installments beginning period.

Dec. 31, 2016

Proceeds receivable quarterly installments ending period.

Jun. 30, 2019

Expiration of quarterly measurement period number | QuarterlyInstallment

5

Expiration of quarterly measurement period number with average spot price | QuarterlyInstallment

11

Additional proceeds receivable for first four quarterly installments

$ 0

Area of land held for sale | a

76,000

Number of barrels net production per day | bbl

1,700

Illinois Basin Operations | Maximum | Discontinued Operations Assets Held For Sale

Business Acquisition And Dispositions [Line Items]

Additional proceeds from sale of oil and gas property and equipment

$ 9,900,000

Additional proceeds receivable for remaining seven quarterly installments

$ 5,400,000

Average Spot Price (Details)

Average Spot Price (Details) - Illinois Basin Operations - Discontinued Operations Assets Held For Sale	12 Months Ended
	Dec. 31, 2017$ / bbl	[1]
3/31/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	61.25
6/30/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	61.75
9/30/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	62.25
12/31/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	62.75
3/31/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	63.25
6/30/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	63.75
[1]	Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).

Discontinued Operations_ Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details) - Discontinued Operations Assets Held For Sale - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Assets or liabilities related to discontinued operation	$ 0	$ 0
Illinois Basin Operations
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Assets or liabilities related to discontinued operation	$ 0	$ 0

Summary of Financial Informatio

Summary of Financial Information for Discontinued Operations (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)bbl
Revenues:
TOTAL OPERATING REVENUE	$ 57,758	$ 47,975	$ 47,462	$ 52,071	$ 48,027	$ 34,039	$ 31,265	$ 25,686	$ 205,266	$ 139,017	$ 138,749
Costs and Expenses:
Production and Lease Operating Expense									120,794	104,699	93,892
General and Administrative Expense									17,858	20,621	26,694
Depreciation, Depletion, Amortization and Accretion									59,028	62,874	85,844
Impairment Expense	$ 4,928	$ 11,877	$ 3,032	$ 1,546	$ 29,279	$ 9,563	$ 25,136	$ 10,641	21,383	74,619	283,244
Exploration Expense									527	2,178	2,617
(Gain) Loss on Disposal of Assets									(1,428)	(4,121)	(540)
Interest Expense									48,826	43,519	47,783
Other (Income) Expense									$ 261	2,124	129
Income (Loss) from Discontinued Operations, net of taxes										20,922	(8,251)
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Revenues:
Field Services Revenue											33,086
TOTAL OPERATING REVENUE											33,086
Costs and Expenses:
General and Administrative Expense											1,961
Depreciation, Depletion, Amortization and Accretion											78
Field Service Operating Expense											25,981
(Gain) Loss on Disposal of Assets											(44)
Interest Expense											487
Other (Income) Expense											(57,589)
Total Costs and Expenses (Income)											(29,126)
Income from Discontinued Operations Before Income Taxes											62,212
Income Tax (Expense) Benefit											(24,227)
Income (Loss) from Discontinued Operations, net of taxes											37,985
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Revenues:
Oil Sales										11,282	33,244
TOTAL OPERATING REVENUE										11,282	33,244
Costs and Expenses:
Production and Lease Operating Expense										11,033	25,099
General and Administrative Expense										1,002	2,741
Depreciation, Depletion, Amortization and Accretion										5,100	18,900
Impairment Expense										3,543	62,531
Exploration Expense										143	394
(Gain) Loss on Disposal of Assets										(30,530)	63
Interest Expense										4	23
Other (Income) Expense										65	(14)
Total Costs and Expenses (Income)										(9,640)	109,737
Income from Discontinued Operations Before Income Taxes										20,922	(76,493)
Income Tax (Expense) Benefit											30,257
Income (Loss) from Discontinued Operations, net of taxes										$ 20,922	$ (46,236)
Production:
Crude Oil (Bbls) | bbl										310,388	729,251

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details)	3 Months Ended									12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 13, 2018Well	Jan. 01, 2018Well
Schedule Of Equity Method Investments [Line Items]
Equity Method Investments									$ 0
Impairment Expense	$ 4,928,000	$ 11,877,000	$ 3,032,000	$ 1,546,000	$ 29,279,000	$ 9,563,000	$ 25,136,000	$ 10,641,000		$ 21,383,000	$ 74,619,000	$ 283,244,000
Loss on Equity Method Investments												(411,000)
Pennsylvania | Subsequent Event
Schedule Of Equity Method Investments [Line Items]
Number of wells sold | Well													61	61
RW Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%									40.00%
Impairment charge in percentage									100.00%
Contributions to Equity Method Investments										$ 0	0
Impairment Expense									$ 17,500,000
Loss on Equity Method Investments										$ (2,000,000)	$ (2,000,000)	$ (2,000,000)
RW Gathering, LLC | Subsequent Event
Schedule Of Equity Method Investments [Line Items]
Ownership interest percentage sold														40.00%

Concentrations of Credit Risk -

Concentrations of Credit Risk - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)Customer	Dec. 31, 2016USD ($)Customer
Concentration Risk [Line Items]
Federal Deposit Insurance Corporation's limit for cash balances	$ 250	$ 250
Accounts Receivable	$ 25,974	$ 25,448
Number of major customers | Customer	3	3
Customer Concentration Risk
Concentration Risk [Line Items]
Number of major customers | Customer	3	3
Customer Concentration Risk | Oil And Gas Production
Concentration Risk [Line Items]
Accounts Receivable	$ 22,900	$ 22,200
Customer Concentration Risk | Oil And Gas Production | Three Purchasers
Concentration Risk [Line Items]
Accounts Receivable	$ 19,300	$ 17,500

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017USD ($)Rigs$ / galgal	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Significant probable or possible environmental contingent liabilities	$ 0
Letters of credit	32,000,000	$ 46,500,000
Rent expense	800,000	900,000	$ 1,000,000
Maximum guarantee of payment of obligations	$ 377,200,000
Guarantee obligations period	2,029
Transportation, processing and marketing expenses of condensate, natural gas and natural gas liquids	$ 109,200,000	91,700,000	79,500,000
Production and Lease Operating Expense	120,794,000	104,699,000	93,892,000
2018 | Appalachian Basin
Loss Contingencies [Line Items]
Cost to retain the completion services	$ 7,000,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest	53.20%
Charges incurred for unutilized processing capacity	$ 5,200,000	3,200,000	600,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	16,600,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	16,600,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	16,600,000
Capacity Reservation | 2021
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	16,600,000
Capacity Reservation | 2022
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	16,600,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	$ 65,000,000
Ohio Drilling Operations | Water Supply Commitments
Loss Contingencies [Line Items]
Water supply contract, effective date	Jul. 5, 2017
Water supply contract, maturity date	Jul. 4, 2022
Water contract purchase obligation | gal	150,000,000
Water Fixed price per gallon | $ / gal	0.0075
Future commitment for unpurchased volumes of water, amount	$ 800,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations | Rigs	1
Drilling Commitments | 2018
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs	$ 1,900,000
Pennsylvania Impact Fee
Loss Contingencies [Line Items]
Production and Lease Operating Expense	3,600,000	$ 3,000,000	$ 3,000,000
Natural Gas Transportation Agreements
Loss Contingencies [Line Items]
Letters of credit	$ 31,700,000

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Details) $ in Thousands	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,018	$ 1,013
2,019	1,020
2,020	888
2,021	475
2,022	485
Total	$ 3,881

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,018	$ 50,313
2,019	50,864
2,020	49,526
2,021	46,574
2,022	46,139
Thereafter	464,599
Total	$ 708,015

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details)	Sep. 15, 2017	Jun. 27, 2012USD ($)	Jun. 30, 2007USD ($)	Dec. 31, 2017USD ($)Aircraft$ / h	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jan. 01, 2018	Mar. 31, 2016USD ($)
Related Party Transaction [Line Items]
Lease renewal term	5 years
1% Senior Secured Second Lien Notes
Related Party Transaction [Line Items]
Interest rate				1.00%
8% Senior Secured Second Lien Notes
Related Party Transaction [Line Items]
Interest rate				8.00%
Second Lien Notes
Related Party Transaction [Line Items]
Senior secured second lien notes				$ 4,600,000				$ 633,200,000
Charlie Brown Air Corp
Related Party Transaction [Line Items]
Number of aircrafts in related party transaction | Aircraft				1
Payments for use of aircrafts				$ 0	$ 0	$ 100,000
Charlie Brown Air Two LLC
Related Party Transaction [Line Items]
Number of aircrafts in related party transaction | Aircraft				500
Percentage of membership interest				50.00%
Monthly payment of principal and interest			$ 100,000
Final balloon payment to be paid			$ 600,000
Percentage of loan guaranteed			50.00%
Loan interest and retainer fees				$ 200,000	200,000	300,000
Charlie Brown Air Two LLC | Related Party Debt
Related Party Transaction [Line Items]
Bank loan			$ 1,500,000	$ 800,000	900,000
Shaner Hotel Group Limited Partnership
Related Party Transaction [Line Items]
Percentage of membership interest				50.00%
Annual CPI adjustment capped		2.50%
Shaner Office Holdings, L.P.
Related Party Transaction [Line Items]
Initial monthly rental payments		$ 35,000
Lease term		5 years
Operating lease annual rent				$ 600,000
RW Gathering, LLC
Related Party Transaction [Line Items]
Production and Lease Operating Expense				$ 600,000	600,000	700,000
Ownership interest percentage				40.00%
Due to or from related party				$ 0	$ 0	0
RW Gathering, LLC | Subsequent Event
Related Party Transaction [Line Items]
Ownership interest percentage sold							40.00%
Water Solutions Holding
Related Party Transaction [Line Items]
Water transfer and water purification expenses						6,100,000
Water transfer and water purification expenses eliminated in consolidation						4,700,000
Due to related party						$ 0
Minimum | Charlie Brown Air Corp
Related Party Transaction [Line Items]
Aircraft use right, variable per hour flight rate | $ / h				700
Maximum | Charlie Brown Air Corp
Related Party Transaction [Line Items]
Aircraft use right, variable per hour flight rate | $ / h				1,560

Long-Term Debt - Term Loan - Ad

Long-Term Debt - Term Loan - Additional Information (Details) - USD ($)	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Line of credit facility, amount outstanding		$ 189,500,000	$ 189,500,000	$ 189,500,000
Deferred debt issuance costs		$ 3,500,000	3,500,000	3,500,000
Original issue discount costs				4,300,000
Amortization of debt issuance costs			700,000	$ 1,165,000	$ 1,640,000	$ 2,045,000
Amortization of original issue discount costs			$ 1,000,000
Term loan yield maintenance ending period post effective date				30 months
Term loan yield maintenance effective date ending period				30 months
Term loan yield maintenance effective date after day one				30 months
Term loan yield maintenance ending period post effective date after day one				36 months
Term Loans, Net
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 300,000,000
Debt instrument, interest rate event of default	4.00%
Commitment fee	3.50%
Average interest rate		10.20%
Interest expense				$ 11,000,000
Prepayments of long term debt				$ 0
Criteria PDP coverage ratio		263.00%	263.00%	263.00%
Criteria debt to EBITDAX ratio		300.00%	300.00%	300.00%
Criteria EBITDAX to cash interest expense ratio		260.00%	260.00%	260.00%
Term Loans, Net | 30 Months After Effective Date
Debt Instrument [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	3.00%
Term Loans, Net | 36 Months After Effective Date
Debt Instrument [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	1.00%
Term Loans, Net | Until No More Than $287,950,000
Debt Instrument [Line Items]
Percentage of prepayment on excess cash flow	50.00%
Term Loans, Net | Minimum
Debt Instrument [Line Items]
EBITDAX to cash interest expense ratio		100.00%	100.00%	100.00%
Criteria PDP coverage ratio		165.00%	165.00%	165.00%
EBITDAX to cash interest expense ratio thereafter		130.00%	130.00%	130.00%
Term Loans, Net | Maximum
Debt Instrument [Line Items]
Net senior secured debt to EBITDAX		325.00%	325.00%	325.00%
Term Loans, Net | Adjusted LIBO Rate
Debt Instrument [Line Items]
Debt instrument, floor rate	1.00%
Debt instrument, margin rate	8.75%
Eight Percentage Senior Secured Second Lien Notes Due Two Thousand And Twenty
Debt Instrument [Line Items]
Debt instrument, outstanding amount	$ 25,000,000
Second Lien Notes | Term Loans, Net
Debt Instrument [Line Items]
Percentage of prepayment on excess cash flow	75.00%
Second Lien Notes | Term Loans, Net | Maximum
Debt Instrument [Line Items]
Second lien notes outstanding	$ 287,950,000
Term Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	143,500,000
Line of credit facility, amount outstanding		$ 189,500,000	$ 189,500,000	$ 189,500,000
Secured Delayed Draw Term Loan Facility
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity	$ 156,500,000
Line of credit facility, maturity date	Apr. 28, 2021
Line of credit facility, expiration date	Apr. 28, 2018
Line of credit facility expiration date potential extension period	1 year
Original issue discount costs				1,400,000
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity		$ 32,000,000	$ 32,000,000	$ 32,000,000

Long-Term Debt - Prior Credit A

Long-Term Debt - Prior Credit Agreement - Additional Information (Details) - USD ($) $ in Millions	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Line of credit facility, amount outstanding		$ 189.5
Prior Credit Agreement
Debt Instrument [Line Items]
Unamortized debt issuance cost expensed	$ 3.4
Line of credit facility, amount outstanding			$ 117.7

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Details) - USD ($) shares in Millions	Mar. 31, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Share of common stock		10.1
Gain recognized due to troubled debt exchanges				$ (9,063,000)
Shares issued	8.4
Fair value of stock issued	$ 6,500,000	$ 6,500,000
Accrued and unpaid interest	12,800,000	12,800,000
Third-party debt issuance costs			$ 10,754,000	$ 2,983,000	$ 1,414,000
Issuance of unrestricted common stock shares			0.1	2.4
Gain (Loss) on Extinguishments of Debt			$ (3,029,000)	$ 24,627,000
Trailing quarters fixed charge coverage ratio			225.00%
Fixed charge coverage ratio			110.00%
Senior Notes additional borrowings			$ 161,700,000
Amortization of net premium				$ (100,000)	$ (381,000)
Interest Payments One Through Three
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment				semi-annual
Maximum
Debt Instrument [Line Items]
Senior notes offered for exchange		675,000,000
Senior Notes, Net
Debt Instrument [Line Items]
Discount/Premium on Senior Notes, Net			13,971,000	$ 3,601,000
Amortization of net premium			10,400	5,200
Senior Notes, Net | Interest Expense
Debt Instrument [Line Items]
Amortization of net premium			16,200,000	22,200,000
Cash interest payments			22,400,000	29,700,000
Increase (decrease) in accrued interest			$ 10,200,000	$ (8,400,000)
8.875% Senior Notes | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate			8.875%	8.875%
6.25% Senior Notes | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate			6.25%	6.25%
Second Lien Notes
Debt Instrument [Line Items]
Gain recognized due to troubled debt exchanges		0
Aggregate principal amount	633,200,000	$ 633,200,000	$ 4,600,000
Additional issuance of debt	$ 500,000
Debt instrument initial interest payment date			Oct. 1, 2016
Debt instrument maturity date			Oct. 1, 2020
Third-party debt issuance costs				$ 9,100,000
Expiration grace period			30 days
Debt amount for conversion				45,700,000
Debt instrument redemption date			Apr. 1, 2018
Latest date for equity proceeds to be applied to optional Note redemption			Apr. 1, 2018
Percentage of notes that can be redeemed			35.00%
Second Lien Notes | Interest Payments One Through Three
Debt Instrument [Line Items]
Interest rate	1.00%	1.00%
Second Lien Notes | Interest Payments Four And Thereafter
Debt Instrument [Line Items]
Interest rate	8.00%	8.00%
2020 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 324,000,000	$ 324,000,000
Percentage of senior notes exchanged for new notes	92.60%
Retirement of notes			$ 900,000	$ 27,700,000
2022 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 309,100,000	$ 309,100,000
Percentage of senior notes exchanged for new notes	95.10%
Senior Notes, Net
Debt Instrument [Line Items]
Gain (Loss) on Extinguishments of Debt			$ 400,000

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Net Carrying Value		$ 751,946
Term Loans, Net | Term Loan Draw - due April 2020
Debt Instrument [Line Items]
Principal	$ 189,500
Unamortized net Premium / Discount	(4,711)
Unamortized Debt Issuance Costs	(2,761)
Net Carrying Value	182,028
Senior Notes, Net
Debt Instrument [Line Items]
Principal	600,302	601,177
Unamortized net Premium / Discount	(13,971)	(3,601)
Unamortized Debt Issuance Costs	33,604	7,909
Unamortized Deferred Gain on Debt Restructurings	30,436	32,676
Net Carrying Value	650,371	638,161
Senior Notes, Net | 8.875% Senior Notes due 2020
Debt Instrument [Line Items]
Principal	7,333	7,573
Unamortized net Premium / Discount	20	26
Unamortized Debt Issuance Costs	(80)	(107)
Net Carrying Value	7,273	7,492
Senior Notes, Net | 6.25% Senior Notes due 2022
Debt Instrument [Line Items]
Principal	5,363	5,648
Unamortized Debt Issuance Costs	(67)	(82)
Net Carrying Value	5,296	5,566
Senior Notes, Net | 1% / 8% Second Lien Senior Notes due 2020
Debt Instrument [Line Items]
Principal	587,606	587,956
Unamortized net Premium / Discount	(13,991)	(3,627)
Unamortized Debt Issuance Costs	33,751	8,098
Unamortized Deferred Gain on Debt Restructurings	30,436	32,676
Net Carrying Value	637,802	625,103
Other Long-Term Debt
Debt Instrument [Line Items]
Non-Current Portion of Capital Leases	8,156
Total Capital Lease Obligations	10,082	4,159
Less: Current Portion of Capital Leases	(1,926)
Other Notes Payable		14
Total Capital Lease and Note Payable Obligations		4,173
Less: Current Portion of Capital Leases and Other Notes Payable		(764)
Non-Current Portion of Capital Leases and Other Notes Payable		3,409
Other Long-Term Debt | Due March, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	632	760
Other Long-Term Debt | Due June, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	1,418	2,225
Other Long-Term Debt | Due September, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	1,578	1,174
Other Long-Term Debt | Due May, 2022
Debt Instrument [Line Items]
Total Capital Lease Obligations	$ 6,454
Senior Secured Line of Credit, Net | Revolving Senior Credit Facility
Debt Instrument [Line Items]
Principal		117,670
Unamortized Debt Issuance Costs		(3,885)
Net Carrying Value		$ 113,785

Components of Long-Term Debt 68

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Term Loans, Net
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2020-04
8.875% Senior Notes due 2020 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate	8.875%	8.875%
Debt instrument, maturity year	2,020	2,020
6.25% Senior Notes due 2022 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate	6.25%	6.25%
Debt instrument, maturity year	2,022	2,022
1% / 8% Second Lien Senior Notes due 2020 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate	0.125%	0.125%
Debt instrument, maturity year	2,020	2,020
Due March, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-03	2021-03
Due June, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-06	2021-06
Due September, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-09	2021-09
Due May, 2022 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2022-05	2022-05

Principal Maturity Schedule for

Principal Maturity Schedule for Debt Outstanding (Details) $ in Thousands	Dec. 31, 2017USD ($)
Debt Disclosure [Abstract]
2,018	$ 791,728	[1]
2,019	2,252
2,020	2,636
2,021	2,462
2,022	806
Total	$ 799,884	[2]
[1]	Due to existing and anticipated covenant violations, the Company’s Term Loan and Senior Notes were classified as current at December 31, 2017.
[2]	Does not include $18.7 million net unamortized premium/discount, $30.8 million of net unamortized debt issuance costs, and $30.4 million of unamortized deferred gain on debt restructurings.

Principal Maturity Schedule f70

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) - Debt Restructurings $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Unamortized net Premium / Discount	$ 18.7
Unamortized Debt Issuance Costs	30.8
Unamortized deferred gain on debt restructurings	$ 30.4

Fair Value of Financial and Der

Fair Value of Financial and Derivative Instruments - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives Received (Paid)									$ 10,100	$ (32,571)	$ (55,793)
Senior Line of Credit	$ 189,500								189,500
Senior Notes	600,300								600,300
Derivatives asset (liability)	19,400				$ 28,200				19,400	28,200
Impairment Expense	$ 4,928	$ 11,877	$ 3,032	$ 1,546	$ 29,279	$ 9,563	$ 25,136	$ 10,641	21,383	74,619	283,244
Illinois Basin Operations
Derivatives Fair Value [Line Items]
Fair value of contingent consideration derivative asset									1,700	2,900
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Derivatives Fair Value [Line Items]
Fair value of contingent consideration derivative asset									1,700	2,900
Impairment Expense										3,543	62,531
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives Received (Paid)									(10,100)	32,600	54,900
Changes in Fair Value									$ 0	$ 7,249
Interest Rate Swap
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives Received (Paid)											$ 900

Schedule of Location and Amount

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (1,347)	$ (32,515)	$ 60,176
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(500)	(1,515)	7,132
Refined Products
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net		54	(376)
Natural Gas
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	13,889	(15,036)	37,647
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(13,520)	(17,788)	14,839
Interest Rate Swap
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net			$ 934
Contingent Consideration
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (1,216)	$ 1,770

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / bbl$ / McfbblMcf
Crude Oil 2018 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	72,000
Put Option	42.29
Floor	51.46
Ceiling	61.38
Derivatives asset (liability) | $	$ (92)
Crude Oil 2018 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	18,000
Floor	53
Ceiling	60
Derivatives asset (liability) | $	$ (31)
Crude Oil 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	95,000
Swap	53.93
Derivatives asset (liability) | $	$ (518)
Crude Oil 2019 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	50,250
Put Option	38.81
Floor	48.81
Ceiling	58.35
Derivatives asset (liability) | $	$ (94)
Crude Oil 2019 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	60,250
Floor	45
Ceiling	55.07
Derivatives asset (liability) | $	$ (100)
Crude Oil 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	31,500
Swap	51
Derivatives asset (liability) | $	$ (90)
Crude Oil 2020 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	29,600
Put Option	39.24
Floor	49.24
Ceiling	56.99
Derivatives asset (liability) | $	$ (52)
Crude Oil 2020 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	71,750
Floor	45
Ceiling	55.10
Derivatives asset (liability) | $	$ (133)
Crude Oil 2020 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	24,000
Swap	51
Derivatives asset (liability) | $	$ (90)
Crude Oil
Derivatives Fair Value [Line Items]
Volume | bbl	588,100
Derivatives asset (liability) | $	$ (1,429)
Crude Oil 2021 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	24,000
Put Option	37.50
Floor	47.50
Ceiling	60.25
Derivatives asset (liability) | $	$ (12)
Crude Oil 2021 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	63,750
Floor	45
Ceiling	55.02
Derivatives asset (liability) | $	$ (123)
Crude Oil 2021 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	6,000
Swap	51
Derivatives asset (liability) | $	$ (22)
Crude Oil 2022 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	6,000
Put Option	37.50
Floor	47.50
Ceiling	60.25
Derivatives asset (liability) | $	$ (3)
Crude Oil 2022 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	36,000
Floor	45
Ceiling	54.75
Derivatives asset (liability) | $	$ (69)
Natural Gas 2018 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	10,600,000
Put Option | $ / Mcf	2.33
Floor | $ / Mcf	2.90
Ceiling | $ / Mcf	3.52
Derivatives asset (liability) | $	$ 1,672
Natural Gas 2018 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	4,415,000
Floor | $ / Mcf	2.66
Ceiling | $ / Mcf	3.10
Derivatives asset (liability) | $	$ 37
Natural Gas 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	15,335,000
Swap | $ / Mcf	3.10
Derivatives asset (liability) | $	$ 3,733
Natural Gas 2018 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	12,775,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability) | $	$ (3,604)
Natural Gas 2018 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability) | $	$ 173
Natural Gas 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	5,810,000
Ceiling | $ / Mcf	3.97
Derivatives asset (liability) | $	$ (154)
Natural Gas 2020 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	4,555,000
Put Option	2.23
Floor	2.73
Ceiling	3.30
Derivatives asset (liability) | $	$ 113
Natural Gas 2020 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	4,720,000
Floor	2.51
Ceiling	3.05
Derivatives asset (liability) | $	$ (183)
Natural Gas 2020 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	4,560,000
Swap | $ / Mcf	2.87
Derivatives asset (liability) | $	$ 13
Natural Gas 2020 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | bbl	7,320,000
Swap	(0.84)
Derivatives asset (liability) | $	$ (1,945)
Natural Gas 2021 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	3,037,500
Put Option | $ / Mcf	2.17
Floor | $ / Mcf	2.67
Ceiling | $ / Mcf	3.15
Derivatives asset (liability) | $	$ (30)
Natural Gas 2021 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	2,737,500
Floor	2.50
Ceiling	3.05
Derivatives asset (liability) | $	$ (134)
Natural Gas 2021 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	3,875,000
Swap	2.77
Derivatives asset (liability) | $	$ (87)
Natural Gas 2021 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability) | $	$ (401)
Natural Gas 2023 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability) | $	$ (401)
Natural Gas 2024 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability) | $	$ (401)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	154,735,500
Derivatives asset (liability) | $	$ (5,829)
Natural Gas 2019 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	8,205,000
Put Option	2.27
Floor	2.77
Ceiling	3.40
Derivatives asset (liability) | $	$ 132
Natural Gas 2019 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	7,520,500
Floor	2.54
Ceiling	3.04
Derivatives asset (liability) | $	$ (295)
Natural Gas 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	10,470,000
Swap	2.84
Derivatives asset (liability) | $	$ 154
Natural Gas 2019 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | bbl	12,775,000
Swap	(0.84)
Derivatives asset (liability) | $	$ (3,570)
Natural Gas Liquids Reserves 2018 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,367,572
Swap	33.30
Derivatives asset (liability) | $	$ (10,254)
Natural Gas Liquids Reserves 2018 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,247,500
Swap	12.92
Derivatives asset (liability) | $	$ 900
Natural Gas Liquids Reserves 2019 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	705,922
Swap	30.65
Derivatives asset (liability) | $	$ (2,750)
Natural Gas Liquids Reserves 2019 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	727,500
Swap	12.98
Derivatives asset (liability) | $	$ 306
Natural Gas Liquids Reserves 2019 | C5 Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	8,472
Floor	32.31
Ceiling	50
Swap	55.75
Derivatives asset (liability) | $	$ (17)
Natural Gas Liquids Reserves 2019 | C5 Collars
Derivatives Fair Value [Line Items]
Volume | bbl	113,040
Floor	45
Ceiling	54.83
Derivatives asset (liability) | $	$ (308)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	5,515,772
Derivatives asset (liability) | $	$ (13,877)
Natural Gas 2022 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	2,047,500
Put Option	2.15
Floor	2.65
Ceiling	3.10
Derivatives asset (liability) | $	$ (58)
Natural Gas 2022 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	2,047,500
Floor	2.50
Ceiling	3.05
Derivatives asset (liability) | $	$ (101)
Natural Gas 2022 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	2,730,000
Swap	2.73
Derivatives asset (liability) | $	$ (91)
Natural Gas 2022 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | bbl	3,650,000
Swap	(0.72)
Derivatives asset (liability) | $	$ (401)
Natural Gas Liquids Reserves Twenty Twenty | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	271,276
Swap	37.63
Derivatives asset (liability) | $	$ (1,157)
Natural Gas Liquids Reserves Twenty Twenty | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	448,500
Swap	12.83
Derivatives asset (liability) | $	$ (9)
Natural Gas Liquids Reserves Twenty Twenty | C5 Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	28,134
Floor	32.31
Ceiling	50
Swap	55.75
Derivatives asset (liability) | $	$ (49)
Natural Gas Liquids Reserves Twenty Twenty | C5 Collars
Derivatives Fair Value [Line Items]
Volume | bbl	28,260
Floor	45
Ceiling	54.83
Derivatives asset (liability) | $	$ (77)
Natural Gas Liquids Reserves 2021 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	158,112
Swap	45.62
Derivatives asset (liability) | $	$ (376)
Natural Gas Liquids Reserves 2021 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	251,000
Swap	12.77
Derivatives asset (liability) | $	$ (3)
Natural Gas Liquids Reserves 2022 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	48,984
Swap	50.56
Derivatives asset (liability) | $	$ (74)
Natural Gas Liquids Reserves 2022 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	111,500
Swap	12.69
Derivatives asset (liability) | $	$ (9)

Combined Fair Value of Derivati

Combined Fair Value of Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$ 8,008	$ 1,873
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,719	2,212
Total Derivative Assets	9,727	4,085
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(14,892)	(25,025)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(14,249)	(7,227)
Total Derivative Liabilities	(29,141)	(32,252)
Contingent Consideration | Sale of Illinois Basin
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,251	1,223
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	470	1,713
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	928
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	409
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(10,281)	(9,895)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(4,482)	(2,200)
Natural Gas Liquids | Three Way Collars
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(66)
Natural Gas Liquids | Collars
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(385)
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	3,734	206
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	411	206
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		(4,673)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(423)	(1,004)
Natural Gas | Cap Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		61
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		(3,364)
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	191	232
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		293
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,621)	(640)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(7,120)	(1,260)
Natural Gas | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,721	151
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	429
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(49)	(2,397)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(272)	(1,786)
Natural Gas | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	183
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(146)	(873)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(713)	(115)
Natural Gas | Calls
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(154)	(1,478)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(491)
Natural Gas | Swaption
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		(1,258)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(167)
Crude Oil | Deferred Put Spread
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		(9)
Crude Oil | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(518)	(220)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(202)	(146)
Crude Oil | Three Way Collars
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(92)	(132)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(161)	(58)
Crude Oil | Collars
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(31)	$ (86)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	$ (425)

Fair Value Hierarchy Table for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) - Commodity derivatives - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (19,414)	$ (28,167)
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (19,414)	$ (28,167)

Reconciliation of Commodity Der

Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3) (Details) - Commodity derivatives - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance of Level 3	$ 0	$ (5,506)
Changes in Fair Value	$ 0	7,249
Transfers out of Level 3		(1,564)
Purchases		0
Settlements Received		(179)
Ending Balance of Level 3		$ 0

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Amount
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	$ 650,371	$ 638,161
Secured Lines of Credit	182,028	113,785
Capital Leases and Other Obligations	10,082	4,173
Total	842,481	756,119
Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	265,438	147,605
Secured Lines of Credit	182,028	113,785
Capital Leases and Other Obligations	7,138	3,234
Total	$ 454,604	$ 264,624

Income Tax Expense from Continu

Income Tax Expense from Continuing Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal	$ (2,001)	$ 1,839
State	(597)	597
Deferred:
Federal	(130)		$ 5,773
State			257
Income Tax (Benefit) Expense	$ (2,728)	$ 2,436	$ 6,030

Reconciliation of Income Tax Ex

Reconciliation of Income Tax Expense Using Statutory Rate Compared with Actual Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income (Loss) from continuing operations before noncontrolling interests and income taxes	$ (66,970)	$ (195,201)	$ (346,752)
Statutory U.S. income tax rate	35.00%	35.00%	35.00%
Tax expense recognized using statutory U.S. income tax rate	$ (23,440)	$ (68,320)	$ (121,363)
State income taxes, net of federal income tax benefit	(1,723)	(3,632)	(17,137)
Change in future rates	79,322	(400)	(212)
Permanent differences	1,130	2,264	1,784
Change in valuation allowances	(57,622)	72,784	143,566
Other	(395)	(260)	(608)
Income Tax (Benefit) Expense	$ (2,728)	$ 2,436	$ 6,030
Effective income tax rate	4.07%	(1.25%)	(1.74%)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Line Items]
Deferred tax benefit related to removal of valuation allowance			$ 100,000
Statutory U.S. income tax rate			35.00%	35.00%	35.00%
Tax rate change reduction in net deferred tax asset			$ 79,300,000
Net operating loss deduction limitation percentage of taxable income			80.00%
Current AMT liability				$ 2,000,000
Current state liability				600,000
Deferred Financing Costs	[1]		$ 98,065,000	182,519,000
Valuation allowance for deferred tax assets			154,416,000	212,041,000
Net operating loss carryforwards, federal			407,600,000
Net operating loss carryforwards. state			533,900,000
Estimated annual utilization limit on net operating losses			1,400,000
Accrued interest and penalties relating to unrecognized tax benefits			0	$ 0
Scenario Forecast
Income Tax Disclosure [Line Items]
Statutory U.S. income tax rate		21.00%
Alternative minimum tax credit year		4 years
Tax Year 2016
Income Tax Disclosure [Line Items]
Current tax benefit generated by CODI			2,600,000
Tax Year 2016 | Internal Revenue Service (IRS)
Income Tax Disclosure [Line Items]
Current tax benefit generated by CODI			2,000,000
Tax Year 2016 | State and Local Jurisdiction
Income Tax Disclosure [Line Items]
Current tax benefit generated by CODI			$ 600,000
Earliest Tax Year
Income Tax Disclosure [Line Items]
Federal net operating loss carryforwards, expiration year			2,023
Latest Tax Year
Income Tax Disclosure [Line Items]
Federal net operating loss carryforwards, expiration year			2,037
[1]	Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016.

Components of Deferred Tax Asse

Components of Deferred Tax Assets (Liabilities) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Assets:
Asset retirement obligation		$ 2,647	$ 3,955
Deferred compensation plans		600	1,581
Compensation Accruals		390	762
Unrealized loss on derivatives		5,457	11,760
Net operating loss carryforwards		126,820	79,531
Deferred Financing Costs	[1]	98,065	182,519
Gas Transportation Capacity Commitments		1,697	3,031
Deferred revenue timing differences		388	443
Organization costs		213	391
Percentage depletion carryforward		2,155	2,717
AMT credits		130	2,131
Timing differences - tax partnerships		465	1,046
Other		217	331
Valuation allowances		(154,416)	(212,041)
Total Deferred Tax Assets net of Valuation Allowances		84,828	78,157
Liabilities:
Book basis of oil and gas properties in excess of tax basis		(84,622)	(77,690)
Other		(76)	(467)
Total Deferred Tax Liabilities		(84,698)	$ (78,157)
Net Deferred Tax Asset		$ 130
[1]	Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016.

Expirations by Year for Federal

Expirations by Year for Federal and State Net Operating Loss Carryforwards (Details) - Federal and state $ in Thousands	Dec. 31, 2017USD ($)
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	$ 126,820
Expiration Year, 2023
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	2
Expiration Year, 2024
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	0
Expiration Year, 2025
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	0
Expiration Year, 2026
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	572
Expiration Year, 2027
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	1,183
Expiration Year, 2028
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	35
Expiration Year, 2029
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	18
Expiration Year, 2030
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	95
Expiration Year, 2031
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	2,089
Expiration Year, 2032
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	36
Expiration Year, 2033
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	2,227
Expiration Year, 2034
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	2,730
Expiration Year, 2035
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	39,280
Expiration Year, 2036
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	15,236
Expiration Year, 2037
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	$ 63,317

Earnings Per Common Share - Add

Earnings Per Common Share - Additional Information (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
6.0% convertible perpetual preferred stock, Series A
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Dividend per share percentage	6.00%
Conversion of Preferred Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	2.2	2.2	8.9
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	0.1	1.2	0.4
Performance Based Restricted Stock Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	0.1	0.6	1.1

Earnings Per Share - Computatio

Earnings Per Share - Computation of Basic and Diluted Earning Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Numerator:
Net Loss From Continuing Operations					$ (75,598)	$ (16,477)	$ (52,911)	$ (52,651)	$ (64,242)		$ (197,637)		$ (352,782)
Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests					8,203	21,892	(1,683)	(7,490)			20,922		(10,496)
Less: Preferred Stock Dividends	$ (598)	$ (598)	$ (598)	$ (598)	(650)	(613)	(1,723)	(2,105)	(2,392)		(5,091)		(9,660)
Effect of Preferred Stock Conversions					668		72,316				72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (11,386)	$ (47,132)	$ (10,201)	$ 2,085	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	$ (66,634)		$ (108,822)		$ (372,938)
Denominator:
Weighted Average Common Shares Outstanding - Basic	10,049	9,906	9,881	9,769	9,740	9,080	7,180	5,600	9,902		7,926		5,439
Effect of Dilutive Securities:
Weighted Average Common Shares Outstanding - Diluted	10,049	9,906	9,881	9,769	9,740	9,080	7,180	5,600	9,902		7,926		5,439
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Loss From Continuing Operations					$ (7.77)	$ (1.89)	$ 2.45	$ (9.78)	$ (6.73)	[1]	$ (16.37)	[1]	$ (66.64)	[1]
Basic — Net Income (Loss) From Discontinuing Operations					0.84	2.41	(0.23)	(1.34)			2.64	[1]	(1.93)	[1]
Basic – Net Loss Attributable to Rex Energy Common Shareholders	$ (1.13)	$ (4.76)	$ (1.03)	$ 0.21	(6.93)	0.52	2.22	(11.12)	(6.73)	[1]	(13.73)	[1]	(68.57)	[1]
Diluted — Net Loss From Continuing Operations					(7.77)	(1.89)	2.45	(9.78)	(6.73)	[1]	(16.37)	[1]	(66.64)	[1]
Diluted — Net Income (Loss) From Discontinued Operations					0.84	2.41	(0.23)	(1.34)			2.64	[1]	(1.93)	[1]
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$ (1.13)	$ (4.76)	$ (1.03)	$ 0.21	$ (6.93)	$ 0.52	$ 2.22	$ (11.12)	$ (6.73)	[1]	$ (13.73)	[1]	$ (68.57)	[1]
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Capital Stock - Additional Info

Capital Stock - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	May 12, 2017	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 27, 2016	May 05, 2016	Aug. 12, 2014
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized			100,000,000	100,000,000		100,000,000	200,000,000
Preferred Stock, shares authorized			100,000	100,000
Common Stock, shares outstanding			10,244,394	9,787,146
Issuance of common stock				800,000
Issuance of common stock payment for preferred stock dividend			300,000
Debt converted to common stock			100,000	2,400,000
Reverse stock split			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.
Preferred Stock, par value			$ 0.001	$ 0.001
Preferred Stock, shares issued			3,987	3,987
Preferred Stock, shares outstanding			3,987	3,987
Preferred stock shares converted		10,100,000
Dividends declared on Preferred Stock			$ 1,196		$ 9,660
Accumulated dividends in arrears			$ 598
Common Stock
Schedule Of Capitalization Equity [Line Items]
Issuance of common stock				841,000
Issuance of common stock payment for preferred stock dividend			314,000	6,000
Reverse stock split	one-for-ten
Preferred stock convertible preferred stock				900,000
6.0% convertible perpetual preferred stock, Series A
Schedule Of Capitalization Equity [Line Items]
Preferred Stock, par value			$ 0.001	$ 0.001
Preferred Stock, shares issued			3,987	3,987
Preferred Stock, shares outstanding			3,987	3,987
Preferred stock shares converted				12,113
Dividend per share in amount			$ 600
Dividend per share percentage			6.00%
Dividends declared on Preferred Stock			$ 1,800		$ 9,700
Cash dividend paid per share			$ 150	$ 0
Aggregate amount of cash dividend paid			$ 1,200
Preferred dividend paid per share			$ 150
Preferred Dividends in Arrears Paid in Common Shares			$ 600
Accumulated dividends in arrears			$ 3,000
Initial conversion price per share of common stock			$ 18
Premium percentage over market closing sale price			25.20%
Closing sale price per share of common stock								$ 14.38
Sale of shares transaction date			Aug. 12, 2014
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Liquidation preference per share			$ 10,000
Preferred stock to common stock conversion ratio			0.5556
Common Stock
Schedule Of Capitalization Equity [Line Items]
Preferred stock to common stock conversion ratio			55.56

Major Customers - Additional In

Major Customers - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)Customer	Dec. 31, 2016USD ($)Customer	Dec. 31, 2015USD ($)Customer
Revenue, Major Customer [Line Items]
Number of customers	3	3
Customer Concentration Risk
Revenue, Major Customer [Line Items]
Number of customers	3	3
Sales
Revenue, Major Customer [Line Items]
Number of customers	3	3	3
Sales | Largest single purchaser
Revenue, Major Customer [Line Items]
Sales revenue | $	$ 86.1	$ 55.1	$ 76
Sales | Customer Concentration Risk | Three customers
Revenue, Major Customer [Line Items]
Sales revenue | $	$ 143.8	$ 95.1	$ 120
Percentage of revenue from major customers	78.50%	78.80%	82.20%
Sales | Customer Concentration Risk | Largest single purchaser
Revenue, Major Customer [Line Items]
Percentage of revenue from major customers	47.00%	45.60%	52.00%

Employee Benefit and Equity P87

Employee Benefit and Equity Plans - Additional Information (Details) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2015USD ($)shares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)Employees$ / sharesshares	Dec. 31, 2015USD ($)Entity$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employer contribution to the plan				$ 500
Number of option issued to purchase common stock | shares		0	88,892
Share-based compensation		$ 1,231	$ 2,959	$ 6,549
Stock options exercised | shares		0	0	0
Weighted average remaining term of options exercisable (in years)		4 years 2 months 12 days	1 year 2 months 12 days
Unrecognized compensation expense		$ 100
Restricted Stock or Unit Expense	$ 2,500
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of employees | Employees			34
Share-based compensation		400	$ 400
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation		900	$ 2,700	$ 5,800
Unrecognized compensation expense		$ 600
Common stock issued by compensation committee | shares		101,237	142,309	223,684
Fair value of TSR awards of per share estimated on date of grant | $ / shares		$ 5.18	$ 9.10	$ 33.50
Expected Dividend Yield		0.00%
Unrecognized compensation expense weighted average period, in years		1 year 4 months 24 days
Total fair value of stock awards vested in period		$ 400	$ 600
Vested stock | shares		102,351	87,206	60,636
Restricted Stock | Certain Performance Factors Waived
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested stock | shares	18,987
Minimum | Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options		5 years
Minimum | Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of companies in peer group | Entity				13
Maximum | Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options		10 years
Maximum | Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of companies in peer group | Entity				15
2007 Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares authorized for issuance | shares		597,947
Shares available for grant | shares		217,552	238,579
TSR | Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value of TSR awards of per share estimated on date of grant | $ / shares				$ 2.56

Summary of Stock Option Activit

Summary of Stock Option Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Beginning Balance, Number of Shares	118,122	44,379	40,268
Granted, Number of Shares		88,892	8,000
Exercised, Number of Shares	0	0	0
Cancelled/Forfeited, Number of Shares	(31,791)	(15,149)	(3,889)
Ending Balance, Number of Shares	86,331	118,122	44,379
Options Exercisable, Number of Shares	32,746
Beginning Balance, Weighted Average Exercise Price	$ 41.40	$ 96.40	$ 108.20
Granted, Weighted Average Exercise Price		16.60	44.80
Cancelled/Forfeited, Weighted Average Exercise Price	72.60	57.20	112.30
Ending Balance, Weighted Average Exercise Price	29.90	$ 41.40	$ 96.40
Options Exercisable, Weighted Average Exercise Price	$ 45.30
Options Outstanding December 31, Weighted Average Remaining Term (in years)	4 years 8 months 12 days
Options Exercisable December 31, Weighted Average Remaining Term (in years)	4 years 2 months 12 days	1 year 2 months 12 days

Assumptions Used to Estimate Fa

Assumptions Used to Estimate Fair Value of Options Granted (Details) - Black-Scholes Options Pricing Model	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected dividend yield	0.00%	0.00%
Expected stock price volatility, minimum	87.80%	87.80%
Expected stock price volatility, maximum	96.50%	96.50%
Risk-free interest rate, minimum	1.10%	1.10%
Risk-free interest rate, maximum	1.50%	1.50%
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected life of options (years)	4 years	4 years
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected life of options (years)	5 years	5 years

Summary of Issued and Outstandi

Summary of Issued and Outstanding Stock Options (Details) - $ / shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding	86,331	118,122	44,379	40,268
Weighted-Average Exercise Price, Outstanding	$ 29.90	$ 41.40	$ 96.40	$ 108.20
Number Exercisable	32,746
Weighted-Average Exercise Price, Exercisable	$ 45.30
Exercise Price Range 9.70
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.70
Number Outstanding	2,750
Weighted-Average Exercise Price, Outstanding	$ 9.70
Number Exercisable	919
Weighted-Average Exercise Price, Exercisable	$ 9.70
Exercise Price Range 16.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 16.90
Number Outstanding	67,294
Weighted-Average Exercise Price, Outstanding	$ 16.90
Number Exercisable	22,873
Weighted-Average Exercise Price, Exercisable	$ 16.90
Exercise Price Range 40.50
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 40.50
Number Outstanding	4,000
Weighted-Average Exercise Price, Outstanding	$ 40.50
Exercise Price Range 49.00
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 49
Number Outstanding	4,000
Weighted-Average Exercise Price, Outstanding	$ 49
Number Exercisable	667
Weighted-Average Exercise Price, Exercisable	$ 49
Exercise Price Range 50.40
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 50.40
Number Outstanding	3,070
Weighted-Average Exercise Price, Outstanding	$ 50.40
Number Exercisable	3,070
Weighted-Average Exercise Price, Exercisable	$ 50.40
Exercise Price Range 104.20
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 104.20
Number Outstanding	2,217
Weighted-Average Exercise Price, Outstanding	$ 104.20
Number Exercisable	2,217
Weighted-Average Exercise Price, Exercisable	$ 104.20
Exercise Price Range 223.40
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 223.40
Number Outstanding	3,000
Weighted-Average Exercise Price, Outstanding	$ 223.40
Number Exercisable	3,000
Weighted-Average Exercise Price, Exercisable	$ 223.40

Percentage of Awards to Vest (D

Percentage of Awards to Vest (Details) - Restricted Stock	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
TSR Rank 1 - 3
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	100.00%	100.00%	100.00%
TSR Rank 4 - 6
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	75.00%	75.00%	75.00%
TSR Rank 7 - 10
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	50.00%	50.00%	50.00%
TSR Rank 11 - 13
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	25.00%	25.00%	25.00%
TSR Rank 14 - 16
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	0.00%	0.00%	0.00%

Monte Carlo Simulation Model As

Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Details) - Monte Carlo Simulation Model	12 Months Ended
	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Dividend Yield	0.00%
Risk-Free Interest Rate	1.00%
Expected Volatility	58.60%
Market Index	35.60%
Expected Life	3 years
Peer Group
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Volatility Rate Minimum	29.80%
Expected Volatility Rate Maximum	85.00%

Summary of Nonvested Stock Acti

Summary of Nonvested Stock Activity (Details) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	242,824	248,016	152,005
Awards, Number of Shares	101,237	142,309	223,684
Vested, Number of Shares	(102,351)	(87,206)	(60,636)
Forfeitures, Number of Shares	(41,235)	(60,295)	(67,037)
Stock awards, ending balance, Number of Shares	200,475	242,824	248,016
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 26.30	$ 62.70	$ 140.50
Awards, Weighted Average Grant Date Fair Value	5.18	9.10	33.50
Vested, Weighted Average Grant Date Fair Value	21.52	73.30	93.90
Forfeitures, Weighted Average Grant Date Fair Value	48.17	67.30	113.30
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 13.62	$ 26.30	$ 62.70

Impairment Expense - Additional

Impairment Expense - Additional Information (Details) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Jun. 30, 2015

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 4,928

$ 11,877

$ 3,032

$ 1,546

$ 29,279

$ 9,563

$ 25,136

$ 10,641

$ 21,383

$ 74,619

$ 283,244

RW Gathering, LLC

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 17,500

Unproved Property Impairments

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

11,500

Proved Properties

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

223,600

Proved Properties | RW Gathering, LLC

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

17,500

Appalachian Basin | Unconventional Proved Properties

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

9,900

28,300

Appalachian Basin | Unproved Property Impairments

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

59,600

Appalachian Basin | Proved Properties

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 204,600

Butler County, Pennsylvania and Ohio | Unproved Property Impairments

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

7,800

$ 46,300

Non-operated Marcellus Leases | Unproved Property Impairments

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

3,200

Marcellus and Utica Shale

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Unproved properties, cost

$ 186,500

$ 186,500

Net Change in Capitalized Explo

Net Change in Capitalized Exploratory Well Costs (Detail)	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)Project
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Beginning Balance at January 1,	$ 17,201,000	$ 16,970,000	$ 22,573,000
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves	91,166,000	46,759,000	144,333,000
Divested wells	(31,000)
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves	(107,883,000)	(39,126,000)	(147,054,000)
Capitalized exploratory well costs charged to expense		(7,402,000)	(2,882,000)
Ending Balance at December 31,	453,000	17,201,000	16,970,000
Less exploratory well costs that have been capitalized for a period of one year or less	(453,000)	(17,201,000)	(12,049,000)
Capitalized exploratory well costs for a period of greater than one year	$ 0	$ 0	$ 4,921,000
Number of projects that have exploratory well costs capitalized for a period of more than one year | Project			13

Suspended Exploratory Well Co96

Suspended Exploratory Well Costs - Additional Information (Detail)	Dec. 31, 2017USD ($)Well	Dec. 31, 2016USD ($)Well	Dec. 31, 2015USD ($)
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory well costs for a period of greater than one year | $	$ 0	$ 0	$ 4,921,000
Pennsylvania Impact Fee
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory number of wells | Well	13	13

Costs Incurred in Oil and Nat97

Costs Incurred in Oil and Natural Gas Property Acquisitions and Development (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition of Properties
Exploration Costs		$ 527	$ 2,178	$ 2,617
Development Costs		416		231
Subtotal		138,294	40,309	193,928
Asset Retirement Obligations		797	1,927	2,739
Total Costs Incurred		141,285	44,414	205,075
Consolidated Entities
Acquisition of Properties
Unproved		3,805	6,671	27,933
Exploration Costs	[1]	90,700	24,650	157,067
Development Costs	[1]	45,983	11,166	17,336
Subtotal		140,488	42,487	202,336
Asset Retirement Obligations		797	1,927	2,739
Total Costs Incurred		141,285	44,414	205,075
Equity Method Investee
Acquisition of Properties
Development Costs	[1]	800	793	824
Subtotal		$ 800	$ 793	$ 824
[1]	Includes Depreciation expense for support equipment and facilities

Reconciliation of Total Costs I

Reconciliation of Total Costs Incurred for Consolidated Entities to Reported Capital Expenditures (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Total Costs Incurred		$ 141,285	$ 44,414	$ 205,075
Illinois Basin Expenditures				15,405
Exploration Expense		(527)	(2,178)	(2,617)
Asset Retirement Obligations		(797)	(1,927)	(2,739)
Depreciation for Support Equipment and Facilities		(2,170)		(4,905)
Corporate Expenditures		416		231
Other	[1]	87		(16,522)
Subtotal		$ 138,294	$ 40,309	$ 193,928
[1]	Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and BSP and intercompany capital transactions.

Capitalized Costs for Natural G

Capitalized Costs for Natural Gas and Oil Production Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Consolidated Entities
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proven Oil and Natural Gas Properties	$ 1,086,625	$ 1,055,467
Pipelines and Support Equipment	18,902	21,088
Field Operation Vehicles and Other Equipment	9,586	11,239
Wells and Facilities in Progress	38,660	21,964
Unproven Properties	186,523	215,794
Total	1,340,296	1,325,552
Less Accumulated Depreciation and Depletion	(459,652)	(474,046)
Total	880,644	851,506
Equity Method Investee
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Pipelines and Support Equipment	19,963	19,962
Total	19,963	19,962
Less Accumulated Depreciation and Depletion	(5,011)	(4,211)
Total	$ 14,952	$ 15,751

Summary of Changes in Estimated

Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells (Details)	12 Months Ended
	Dec. 31, 2017MMcfebblMcf	Dec. 31, 2016MMcfebblMcf	Dec. 31, 2015MMcfebblMcf
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period | MMcfe	647,783,100	680,445,000	1,336,808,300
Extensions, Discoveries and Additions | MMcfe	309,571,700	26,427,800	142,986,700
Revisions of Previous Estimates | MMcfe	165,172,500	59,144,700	(703,020,300)
Sales of Reserves | MMcfe	(21,563,800)	(46,809,500)
Purchases | MMcfe			(24,854,900)
Production | MMcfe	(68,077,400)	(71,424,900)	(71,474,800)
Estimated Proved Reserves-End of Period | MMcfe	1,032,886,100	647,783,100	680,445,000
Proved Developed Reserves Energy Equivalents | MMcfe	920,962,000	647,783,100	647,073,400
Proved Undeveloped Reserves Energy Equivalents | MMcfe	111,923,900		33,371,600
Oil
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	1,866,000	5,317,100	9,684,700
Extensions, Discoveries and Additions	1,929,600	373,500	949,000
Revisions of Previous Estimates	90,000	323,900	(4,176,800)
Sales of Reserves	(144,500)	(3,788,100)
Purchases			(7,700)
Production	(271,800)	(360,400)	(1,132,100)
Estimated Proved Reserves-End of Period	3,469,300	1,866,000	5,317,100
Proved Developed Reserves	2,235,400	1,865,900	4,944,600
Proved Undeveloped Reserves	1,233,900		372,500
Natural Gas Liquids
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	44,824,400	40,346,600	73,252,500
Extensions, Discoveries and Additions	22,295,200	2,183,700	10,079,300
Revisions of Previous Estimates	10,225,700	8,262,000	(38,249,700)
Sales of Reserves	(984,400)	(1,860,500)
Purchases			(1,389,600)
Production	(4,079,100)	(4,107,400)	(3,345,900)
Estimated Proved Reserves-End of Period	72,281,800	44,824,400	40,346,600
Proved Developed Reserves	64,738,500	44,824,400	37,941,900
Proved Undeveloped Reserves	7,543,300		2,404,700
Natural Gas
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period | Mcf	367,640,900	406,462,800	839,185,100
Extensions, Discoveries and Additions | Mcf	164,222,700	11,084,600	76,816,900
Revisions of Previous Estimates | Mcf	103,278,300	7,629,300	(448,461,300)
Sales of Reserves | Mcf	(14,790,400)	(12,917,700)
Purchases | Mcf			(16,471,100)
Production | Mcf	(41,972,000)	(44,618,100)	(44,606,800)
Estimated Proved Reserves-End of Period | Mcf	578,379,500	367,640,900	406,462,800
Proved Developed Reserves | Mcf	519,118,600	367,641,300	389,754,400
Proved Undeveloped Reserves | Mcf	59,260,900		16,708,400

Oil and Natural Gas Reserve 101

Oil and Natural Gas Reserve Quantities - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017MMcfeMMBoe	Dec. 31, 2016MMcfeMMBoe	Dec. 31, 2015MMcfeMMBoe
Reserve Quantities [Line Items]
Discount rate	10.00%
Revisions	165,000	59,100
Crude Oil
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions | MMBoe	1.9	0.4	0.9
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions | MMBoe	22.3	2.2	10.1
Natural Gas
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions	164,000	11,100	76,800
Lower Commodity Prices
Reserve Quantities [Line Items]
Revisions			(741,100)
Ethane Recovery Expectations
Reserve Quantities [Line Items]
Revisions			4,100
Technical Revisions
Reserve Quantities [Line Items]
Revisions			18.6
Well Performance
Reserve Quantities [Line Items]
Revisions | MMBoe			(2,200)
Operating Expense
Reserve Quantities [Line Items]
Revisions			15,400
Butler
Reserve Quantities [Line Items]
Revisions			10,300
Warrior North Prospect in Ohio
Reserve Quantities [Line Items]
Revisions			9,800
Marcellus and Utica Shale
Reserve Quantities [Line Items]
Percentage Of Proved Undeveloped Reserves Extensions Discoveries And Additions	100.00%

Standardized Measure of Disc102

Standardized Measure of Discounted Future Net Cash Flows - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Annual discount factor	10.00%

Summary of Future Net Cash Flow

Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Future Cash Inflows	$ 2,952,274	[1]	$ 1,371,210	[2]	$ 1,716,131	[3]
Production	(1,721,109)		(1,061,275)		(1,144,049)
Abandonment	(9,866)		(47,159)		(143,459)
Development	(45,365)				(18,952)
Net Future Cash Inflow Before Income Taxes	1,175,934		262,776		409,671
Future Income Tax Expense	(24,105)
Total Future Net Cash Flows Before 10.0% Discount	1,151,829		262,776		409,671
Less: Effect of 10.0% Discount Factor	(644,810)		(97,179)		(154,048)
Standardized Measure of Discounted Future Net Cash Flows	$ 507,019		$ 165,597		$ 255,623		$ 1,025,364
[1]	Calculated using weighted average prices of $2.793 per Mcf, $45.62 per barrel of oil and $16.31 per barrel of NGLs
[2]	Calculated using weighted average prices of $2.264 per Mcf, $36.68 per barrel of oil and $10.50 per barrel of NGLs
[3]	Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs

Summary of Future Net Cash F104

Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2017$ / bbl$ / Mcf	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices | $ / Mcf	2.793	2.264	2.401
Crude Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices	45.62	36.68	44.45
Natural Gas Liquids
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices	16.31	10.50	12.48

Principal Sources of Change in

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Standardized Measure – Beginning of Period	$ 165,597	$ 255,623	$ 1,025,364
Changes in Prices and Production Costs	137,000	(89,583)	(1,296,866)
Revisions in Quantities	78,276	9,851	(270,673)
Changes in Future Development Costs	(41,803)	7,786	595,547
Accretion of Discount and Timing of Future Cash Flows	16,560	25,562	116,514
Net Change in Income Tax	(24,105)		139,776
Purchase (Sale) of Reserves in Place	(6,692)	(54,598)	(37,101)
Plus Extensions, Discoveries, and Other Additions	166,867	21,841	88,152
Development Costs Incurred	45,983	11,166	31,574
Sales of Product – Net of Production Costs	(84,452)	(34,301)	(52,952)
Changes in Timing and Other	53,788	12,250	(83,712)
Standardized Measure – End of Period	$ 507,019	$ 165,597	$ 255,623

Results of Operations (Details)

Results of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Expenses
Results of Operations for Oil and Gas Producing Activities		$ 2,832	$ (107,493)	$ (333,361)
Consolidated Entities
Revenues
Oil and Natural Gas Sales		205,266	139,017	138,749
Expenses
Production and Lease Operating Expense		120,794	104,699	93,892
Impairment Expense		21,383	74,619	283,244
Exploration Expense		527	2,178	2,617
Depletion, Depreciation, Amortization and Accretion		59,028	62,874	85,844
Total Costs		201,732	244,370	465,597
Pre-Tax Operating Income (Loss)		3,534	(105,353)	(326,848)
Income Tax Benefit (Expense)	[1]	144	(1,317)	(5,687)
Results of Operations for Oil and Gas Producing Activities		3,678	(106,670)	(332,535)
Equity Method Investee
Expenses
Depletion, Depreciation, Amortization and Accretion		813	813	812
Total Costs		813	813	812
Pre-Tax Operating Income (Loss)		(813)	(813)	(812)
Income Tax Benefit (Expense)	[1]	(33)	(10)	(14)
Results of Operations for Oil and Gas Producing Activities		$ (846)	$ (823)	$ (826)
[1]	Computed using the effective rate for continuing operations for each period: 4.07% in 2017; -1.25% in 2016 and; -1.74% in 2015.

Results of Operations (Parenthe

Results of Operations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Effective tax rate	4.07%	(1.25%)	(1.74%)

Litigation - Additional Informa

Litigation - Additional Information (Details)	1 Months Ended		12 Months Ended
	Jul. 31, 2012Case	Oct. 31, 2011Plaintiff	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Number of plaintiffs | Plaintiff		2
Case dismissed date			May 9, 2012
Case dismissal appeal date			May 16, 2012
Case revised decision date			May 3, 2013
Additional lawsuits | Case	2

Unaudited Financial Information

Unaudited Financial Information on Quarterly Basis (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 57,758	$ 47,975	$ 47,462	$ 52,071	$ 48,027	$ 34,039	$ 31,265	$ 25,686	$ 205,266		$ 139,017		$ 138,749
Impairment Expense	4,928	11,877	3,032	1,546	29,279	9,563	25,136	10,641	21,383		74,619		283,244
Other Costs and Expenses	63,618	82,632	54,033	47,842	94,346	40,953	59,040	67,696
NET LOSS FROM CONTINUING OPERATIONS					(75,598)	(16,477)	(52,911)	(52,651)	(64,242)		(197,637)		(352,782)
Net Income (Loss) From Discontinued Operations, Net of Income Taxes					8,203	21,892	(1,683)	(7,490)			20,922		(10,496)
NET LOSS ATTRIBUTABLE TO REX ENERGY	(10,788)	(46,534)	(9,603)	2,683	(67,395)	5,415	(54,594)	(60,141)	(64,242)		(176,715)		(363,278)
Preferred Stock Dividends	(598)	(598)	(598)	(598)	(650)	(613)	(1,723)	(2,105)	(2,392)		(5,091)		(9,660)
Effect of Preferred Stock Conversions					668		72,316				72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (11,386)	$ (47,132)	$ (10,201)	$ 2,085	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	$ (66,634)		$ (108,822)		$ (372,938)
Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Continuing Operations					$ (7.77)	$ (1.89)	$ 2.45	$ (9.78)	$ (6.73)	[1]	$ (16.37)	[1]	$ (66.64)	[1]
Basic — Discontinued Operations					0.84	2.41	(0.23)	(1.34)			2.64	[1]	(1.93)	[1]
Basic — Net Income (Loss)	$ (1.13)	$ (4.76)	$ (1.03)	$ 0.21	$ (6.93)	$ 0.52	$ 2.22	$ (11.12)	$ (6.73)	[1]	$ (13.73)	[1]	$ (68.57)	[1]
Basic — Weighted Average Shares Outstanding	10,049	9,906	9,881	9,769	9,740	9,080	7,180	5,600	9,902		7,926		5,439
Diluted — Continuing Operations					$ (7.77)	$ (1.89)	$ 2.45	$ (9.78)	$ (6.73)	[1]	$ (16.37)	[1]	$ (66.64)	[1]
Diluted — Discontinued Operations					0.84	2.41	(0.23)	(1.34)			2.64	[1]	(1.93)	[1]
Diluted — Net Income (Loss)	$ (1.13)	$ (4.76)	$ (1.03)	$ 0.21	$ (6.93)	$ 0.52	$ 2.22	$ (11.12)	$ (6.73)	[1]	$ (13.73)	[1]	$ (68.57)	[1]
Diluted — Weighted Average Shares Outstanding	10,049	9,906	9,881	9,769	9,740	9,080	7,180	5,600	9,902		7,926		5,439
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Condensed Consolidating Fina110

Condensed Consolidating Financial Information - Additional Information (Details) $ in Millions	Dec. 31, 2017USD ($)
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Gross	$ 600.3

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents	$ 15,247	$ 3,697	$ 1,091
Accounts Receivable	25,974	25,448
Taxes Receivable	2,049	211
Short-Term Derivative Instruments	8,008	1,873
Inventory, Prepaid Expenses and Other	4,614	2,546
Total Current Assets	55,892	33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,086,625	1,053,461
Unevaluated Oil and Gas Properties	186,523	215,794
Other Property and Equipment	19,640	21,401
Wells and Facilities in Progress	38,660	21,964
Pipelines	16,803	18,029
Total Property and Equipment	1,348,251	1,330,649
Less: Accumulated Depreciation, Depletion and Amortization	(463,899)	(475,205)
Net Property and Equipment	884,352	855,444
Other Assets	44	2,492
Deferred Financing Costs and Other Assets—Net		2,492
Long-Term Derivative Instruments	1,719	2,212
Deferred Tax Assets - Long Term	130
Total Assets	942,137	893,923
Current Liabilities
Accounts Payable	62,354	40,712
Current Maturities of Long-Term Debt	834,325	764
Accrued Liabilities	45,218	37,207
Short-Term Derivative Instruments	14,892	25,025
Total Current Liabilities	956,789	103,708
Long-Term Derivative Instruments	14,249	7,227
Long-Term Debt		751,946
Other Long-Term Debt	8,156	3,409
Other Deposits and Liabilities	7,153	8,671
Future Abandonment Cost	9,352	8,736
Total Liabilities	995,699	883,697
Stockholders’ Equity
Preferred Stock	1	1
Common Stock	10	10
Additional Paid-In Capital	652,917	650,669
Accumulated Deficit	(706,490)	(640,454)
Total Stockholders’ Equity (Deficit)	(53,562)	10,226	$ 160,231	$ 531,373
Total Liabilities and Stockholders’ Equity (Deficit)	942,137	893,923
Eliminations
Property and Equipment (Successful Efforts Method)
Intercompany Receivables	(1,072,637)	(1,035,713)
Investment in Subsidiaries – Net	274,745	130,362
Total Assets	(797,892)	(905,351)
Current Liabilities
Intercompany Payables	(1,072,637)	(1,035,713)
Total Liabilities	(1,072,637)	(1,035,713)
Stockholders’ Equity
Additional Paid-In Capital	(177,144)	(177,144)
Accumulated Deficit	451,889	307,506
Total Stockholders’ Equity (Deficit)	274,745	130,362
Total Liabilities and Stockholders’ Equity (Deficit)	(797,892)	(905,351)
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents	15,244	3,694
Accounts Receivable	25,974	22,609
Short-Term Derivative Instruments	8,008	1,873
Inventory, Prepaid Expenses and Other	2,106	2,521
Total Current Assets	51,332	30,697
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,086,625	1,053,461
Unevaluated Oil and Gas Properties	186,523	215,794
Other Property and Equipment	19,640	21,401
Wells and Facilities in Progress	38,660	21,964
Pipelines	16,803	18,029
Total Property and Equipment	1,348,251	1,330,649
Less: Accumulated Depreciation, Depletion and Amortization	(463,899)	(475,205)
Net Property and Equipment	884,352	855,444
Other Assets	44
Deferred Financing Costs and Other Assets—Net		2,492
Investment in Subsidiaries – Net	(2,484)	(2,388)
Long-Term Derivative Instruments	(2)	(723)
Total Assets	933,242	885,522
Current Liabilities
Accounts Payable	62,354	40,712
Current Maturities of Long-Term Debt	1,926	764
Accrued Liabilities	32,214	32,328
Short-Term Derivative Instruments	14,892	25,025
Total Current Liabilities	111,386	98,829
Long-Term Derivative Instruments	14,249	7,227
Other Long-Term Debt	8,156	3,409
Other Deposits and Liabilities	7,153	8,671
Future Abandonment Cost	9,352	8,736
Intercompany Payables	1,068,231	1,032,050
Total Liabilities	1,218,527	1,158,922
Stockholders’ Equity
Additional Paid-In Capital	177,144	177,144
Accumulated Deficit	(462,429)	(450,544)
Total Stockholders’ Equity (Deficit)	(285,285)	(273,400)
Total Liabilities and Stockholders’ Equity (Deficit)	933,242	885,522
Non-Guarantor Subsidiaries
Current Liabilities
Accrued Liabilities		421
Total Current Liabilities		421
Intercompany Payables	4,406	3,663
Total Liabilities	4,406	4,084
Stockholders’ Equity
Accumulated Deficit	(4,406)	(4,084)
Total Stockholders’ Equity (Deficit)	(4,406)	(4,084)
Parent Company
Current Assets
Cash and Cash Equivalents	3	3
Accounts Receivable		2,839
Taxes Receivable	2,049	211
Inventory, Prepaid Expenses and Other	2,508	25
Total Current Assets	4,560	3,078
Property and Equipment (Successful Efforts Method)
Intercompany Receivables	1,072,637	1,035,713
Investment in Subsidiaries – Net	(272,261)	(127,974)
Long-Term Derivative Instruments	1,721	2,935
Deferred Tax Assets - Long Term	130
Total Assets	806,787	913,752
Current Liabilities
Current Maturities of Long-Term Debt	832,399
Accrued Liabilities	13,004	4,458
Total Current Liabilities	845,403	4,458
Long-Term Debt		751,946
Total Liabilities	845,403	756,404
Stockholders’ Equity
Preferred Stock	1	1
Common Stock	10	10
Additional Paid-In Capital	652,917	650,669
Accumulated Deficit	(691,544)	(493,332)
Total Stockholders’ Equity (Deficit)	(38,616)	157,348
Total Liabilities and Stockholders’ Equity (Deficit)	$ 806,787	$ 913,752

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales									$ 205,246	$ 139,000	$ 138,707
Other Revenue									20	17	42
TOTAL OPERATING REVENUE	$ 57,758	$ 47,975	$ 47,462	$ 52,071	$ 48,027	$ 34,039	$ 31,265	$ 25,686	205,266	139,017	138,749
OPERATING EXPENSES
Production and Lease Operating Expense									120,794	104,699	93,892
General and Administrative Expense									17,858	20,621	26,694
Gain on Disposal of Assets									(1,428)	(4,121)	(540)
Impairment Expense	4,928	11,877	3,032	1,546	29,279	9,563	25,136	10,641	21,383	74,619	283,244
Exploration Expense									527	2,178	2,617
Depreciation, Depletion, Amortization and Accretion									59,028	62,874	85,844
Other Operating Expense									611	10,754	5,603
TOTAL OPERATING EXPENSES									218,773	271,624	497,354
LOSS FROM OPERATIONS									(13,507)	(132,607)	(358,605)
OTHER INCOME (EXPENSE)
Interest Expense									(48,826)	(43,519)	(47,783)
Gain (Loss) on Derivatives, Net									(1,347)	(32,515)	60,176
Other Income (Expense)									(261)	(2,124)	(129)
Debt Exchange Expense										(9,063)
Gain (Loss) on Extinguishments of Debt									(3,029)	24,627
Loss From Equity Method Investments											(411)
TOTAL OTHER INCOME (EXPENSE)									(53,463)	(62,594)	11,853
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(66,970)	(195,201)	(346,752)
Income Tax Benefit (Expense)									2,728	(2,436)	(6,030)
NET LOSS FROM CONTINUING OPERATIONS					(75,598)	(16,477)	(52,911)	(52,651)	(64,242)	(197,637)	(352,782)
Income (Loss) From Discontinued Operations, Net ofIncome Taxes										20,922	(8,251)
NET LOSS									(64,242)	(176,715)	(361,033)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations											2,245
NET LOSS ATTRIBUTABLE TO REX ENERGY	(10,788)	(46,534)	(9,603)	2,683	(67,395)	5,415	(54,594)	(60,141)	(64,242)	(176,715)	(363,278)
Preferred Stock Dividends	(598)	(598)	(598)	(598)	(650)	(613)	(1,723)	(2,105)	(2,392)	(5,091)	(9,660)
Effect of Preferred Stock Conversions					668		72,316			72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (11,386)	$ (47,132)	$ (10,201)	$ 2,085	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	(66,634)	(108,822)	(372,938)
Eliminations
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in ConsolidatedSubsidiaries									14,646	146,344	309,250
TOTAL OTHER INCOME (EXPENSE)									14,646	146,344	309,250
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									14,646	146,344	309,250
NET LOSS FROM CONTINUING OPERATIONS										146,344	309,250
NET LOSS									14,646	146,344	309,250
NET LOSS ATTRIBUTABLE TO REX ENERGY											309,250
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									14,646	146,344	309,250
Guarantor Subsidiaries
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales									205,246	139,000	138,707
Other Revenue									20	17	42
TOTAL OPERATING REVENUE									205,266	139,017	138,749
OPERATING EXPENSES
Production and Lease Operating Expense									120,794	104,699	93,892
General and Administrative Expense									16,601	17,488	20,849
Gain on Disposal of Assets									(1,428)	(4,121)	(540)
Impairment Expense									21,383	74,624	282,833
Exploration Expense									527	2,177	2,616
Depreciation, Depletion, Amortization and Accretion									58,713	62,849	85,839
Other Operating Expense									611	10,754	5,603
TOTAL OPERATING EXPENSES									217,201	268,470	491,092
LOSS FROM OPERATIONS									(11,935)	(129,453)	(352,343)
OTHER INCOME (EXPENSE)
Interest Expense									(2,288)	(1,326)	(248)
Gain (Loss) on Derivatives, Net									(131)	(34,285)	59,242
Other Income (Expense)									(270)	41	(129)
Income (Loss) From Equity in ConsolidatedSubsidiaries									(309)	(94)	(429)
Loss From Equity Method Investments											(411)
TOTAL OTHER INCOME (EXPENSE)									(2,998)	(35,664)	58,025
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(14,933)	(165,117)	(294,318)
Income Tax Benefit (Expense)									596	(2,060)	(5,111)
NET LOSS FROM CONTINUING OPERATIONS										(167,177)	(299,429)
Income (Loss) From Discontinued Operations, Net ofIncome Taxes										20,887	(45,546)
NET LOSS									(14,337)	(146,290)	(344,975)
NET LOSS ATTRIBUTABLE TO REX ENERGY											(344,975)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(14,337)	(146,290)	(344,975)
Non-Guarantor Subsidiaries
OPERATING EXPENSES
General and Administrative Expense										5
Impairment Expense										(5)	411
Exploration Expense										1	1
Depreciation, Depletion, Amortization and Accretion									315	25	5
TOTAL OPERATING EXPENSES									315	26	417
LOSS FROM OPERATIONS									(315)	(26)	(417)
OTHER INCOME (EXPENSE)
Other Income (Expense)									(7)
Income (Loss) From Equity in ConsolidatedSubsidiaries										94	429
TOTAL OTHER INCOME (EXPENSE)									(7)	94	429
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(322)	68	12
Income Tax Benefit (Expense)									13		(7)
NET LOSS FROM CONTINUING OPERATIONS										68	5
Income (Loss) From Discontinued Operations, Net ofIncome Taxes										(122)	37,965
NET LOSS									(309)	(54)	37,970
Net Income Attributable to Noncontrolling Interests of Discontinued Operations											2,245
NET LOSS ATTRIBUTABLE TO REX ENERGY											35,725
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(309)	(54)	35,725
Parent Company
OPERATING EXPENSES
General and Administrative Expense									1,257	3,128	5,845
TOTAL OPERATING EXPENSES									1,257	3,128	5,845
LOSS FROM OPERATIONS									(1,257)	(3,128)	(5,845)
OTHER INCOME (EXPENSE)
Interest Expense									(46,538)	(42,193)	(47,535)
Gain (Loss) on Derivatives, Net									(1,216)	1,770	934
Other Income (Expense)									16	(2,165)
Debt Exchange Expense										(9,063)
Gain (Loss) on Extinguishments of Debt									(3,029)	24,627
Income (Loss) From Equity in ConsolidatedSubsidiaries									(14,337)	(146,344)	(309,250)
TOTAL OTHER INCOME (EXPENSE)									(65,104)	(173,368)	(355,851)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(66,361)	(176,496)	(361,696)
Income Tax Benefit (Expense)									2,119	(376)	(912)
NET LOSS FROM CONTINUING OPERATIONS										(176,872)	(362,608)
Income (Loss) From Discontinued Operations, Net ofIncome Taxes										157	(670)
NET LOSS									(64,242)	(176,715)	(363,278)
NET LOSS ATTRIBUTABLE TO REX ENERGY											(363,278)
Preferred Stock Dividends									(2,392)	(5,091)	(9,660)
Effect of Preferred Stock Conversions										72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ (66,634)	$ (108,822)	$ (372,938)

Condensed Consolidating Stat113

Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$ (64,242)	$ (176,715)	$ (361,033)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Loss on Equity Method Investments				411
Depreciation, Depletion, Amortization and Accretion		59,028	67,975	104,822
Gain (Loss) on Derivatives		1,347	32,515	(60,176)
Cash Settlements of Derivatives		(10,100)	32,571	55,793
Non-Cash Dry Hole Expense		13	905	330
Equity-based Compensation Expense		1,231	2,959	6,549
Impairment Expense		21,383	78,162	345,775
Amortization of Debt Issuance Costs	$ 700	1,165	1,640	2,045
Amortization of Bond Discounts and Premiums			(100)	(381)
Non-cash Interest Expense related to Debt Restructurings and Exchanges		14,063	19,603
Loss (Gain) on Extinguishment of Debt		3,029	(24,627)
(Gain) Loss on Sale of Assets		(1,428)	(34,651)	(521)
Gain on Sale of Water Solutions				(57,778)
Deferred Income Tax Benefit		(130)
Other Non-cash Income (Expense)		471	22	(564)
Changes in operating assets and liabilities
Accounts Receivable		5,258	(6,414)	21,679
Taxes Receivable		(1,839)
Inventory, Prepaid Expenses and Other Assets		(2,060)	906	(568)
Accounts Payable and Accrued Liabilities		14,558	2,795	(22,955)
Other Assets and Liabilities		(3,259)	(1,950)	(2,543)
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		38,488	(4,404)	30,885
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management				58
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		31,704	40,884	77,226
Proceeds from Joint Venture for reimbursement of capital Costs			19,461	16,611
Acquisitions of Undeveloped Acreage		(3,805)	(6,712)	(28,242)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(113,411)	(48,982)	(221,099)
NET CASH (USED) PROVIDED BY INVESTING ACTIVITIES		(85,512)	4,651	(155,446)
Proceeds from Joint Venture			19,461	16,611
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		217,000	71,400	229,314
Repayments of Long-Term Debt and Lines of Credit		(145,170)	(65,230)	(108,335)
Repayments of Loans and Other Notes Payable		(1,306)	(828)	(1,519)
Debt Issuance Costs		(10,754)	(2,983)	(1,414)
Distributions by the Partners of Consolidated Subsidiary				(830)
Dividends Paid on Preferred Stock		(1,196)		(9,660)
NET CASH PROVIDED BY FINANCING ACTIVITIES		58,574	2,359	107,556
NET INCREASE IN CASH		11,550	2,606	(17,005)
CASH AND CASH EQUIVALENTS – BEGINNING		3,697	1,091	18,096
CASH AND CASH EQUIVALENTS – ENDING	15,247	15,247	3,697	1,091
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		14,646	146,344	309,250
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion				(3,963)
Non-Cash Dry Hole Expense				(5)
Impairment Expense			(78,162)	(347,405)
Changes in operating assets and liabilities
Accounts Receivable				(2,537)
Accounts Payable and Accrued Liabilities				2,537
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		14,646	68,182	(42,123)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		(14,646)	(68,182)	40,959
Capital Expenditures for Development of Oil & Gas Properties and Equipment				1,164
NET CASH (USED) PROVIDED BY INVESTING ACTIVITIES		(14,646)	(68,182)	42,123
CASH FLOWS FROM FINANCING ACTIVITIES
NET INCREASE IN CASH		0
CASH AND CASH EQUIVALENTS – ENDING	0	0
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		(14,337)	(146,290)	(344,975)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Loss on Equity Method Investments				411
Depreciation, Depletion, Amortization and Accretion		58,713	67,915	105,555
Gain (Loss) on Derivatives		131	34,285	(59,242)
Cash Settlements of Derivatives		(10,100)	32,571	54,859
Non-Cash Dry Hole Expense		13	905	199
Equity-based Compensation Expense		(1)	40	99
Impairment Expense		21,383	78,160	345,892
Amortization of Debt Issuance Costs				17
(Gain) Loss on Sale of Assets		(1,428)	(34,697)	(477)
Other Non-cash Income (Expense)		471	(208)	(218)
Changes in operating assets and liabilities
Accounts Receivable		5,261	(44,354)	24,240
Inventory, Prepaid Expenses and Other Assets		(1,159)	906	(431)
Accounts Payable and Accrued Liabilities		6,000	8,815	(20,008)
Other Assets and Liabilities		(3,210)	(1,953)	(2,497)
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		61,737	(3,905)	103,424
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		36,631	3,587	96,664
Proceeds from Joint Venture Acreage Management				58
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		31,704	39,904	9,766
Proceeds from Joint Venture for reimbursement of capital Costs			19,461	16,611
Acquisitions of Undeveloped Acreage		(3,805)	(6,671)	(27,963)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(113,411)	(48,943)	(214,450)
NET CASH (USED) PROVIDED BY INVESTING ACTIVITIES		(48,881)	7,338	(119,314)
Proceeds from Joint Venture			19,461	16,611
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable		(1,306)	(828)	(999)
NET CASH PROVIDED BY FINANCING ACTIVITIES		(1,306)	(828)	(999)
NET INCREASE IN CASH		11,550	2,605	(16,889)
CASH AND CASH EQUIVALENTS – BEGINNING		3,694	1,089	17,978
CASH AND CASH EQUIVALENTS – ENDING	15,244	15,244	3,694	1,089
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		(309)	(54)	37,970
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion		315	60	3,230
Non-Cash Dry Hole Expense				136
Impairment Expense			2	1,396
Amortization of Debt Issuance Costs				13
(Gain) Loss on Sale of Assets			46	(44)
Other Non-cash Income (Expense)				(346)
Changes in operating assets and liabilities
Accounts Receivable			(863)	(453)
Inventory, Prepaid Expenses and Other Assets				(142)
Accounts Payable and Accrued Liabilities				(4,969)
Other Assets and Liabilities			3	(73)
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		6	(806)	36,718
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		(6)	(94)	(37,425)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			980	560
Acquisitions of Undeveloped Acreage			(41)	(279)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(39)	(7,813)
NET CASH (USED) PROVIDED BY INVESTING ACTIVITIES		(6)	806	(44,957)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit				35,814
Repayments of Long-Term Debt and Lines of Credit				(26,335)
Repayments of Loans and Other Notes Payable				(520)
Debt Issuance Costs				(3)
Distributions by the Partners of Consolidated Subsidiary				(830)
NET CASH PROVIDED BY FINANCING ACTIVITIES				8,126
NET INCREASE IN CASH		0	0	(113)
CASH AND CASH EQUIVALENTS – BEGINNING		0	0	113
CASH AND CASH EQUIVALENTS – ENDING	0	0	0	0
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		(64,242)	(176,715)	(363,278)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Gain (Loss) on Derivatives		1,216	(1,770)	(934)
Cash Settlements of Derivatives				934
Equity-based Compensation Expense		1,232	2,919	6,450
Impairment Expense			78,162	345,892
Amortization of Debt Issuance Costs		1,165	1,640	2,015
Amortization of Bond Discounts and Premiums			(100)	(381)
Non-cash Interest Expense related to Debt Restructurings and Exchanges		14,063	19,603
Loss (Gain) on Extinguishment of Debt		3,029	(24,627)
Gain on Sale of Water Solutions				(57,778)
Deferred Income Tax Benefit		(130)
Other Non-cash Income (Expense)			230
Changes in operating assets and liabilities
Accounts Receivable		(3)	38,803	429
Taxes Receivable		(1,839)
Inventory, Prepaid Expenses and Other Assets		(901)		5
Accounts Payable and Accrued Liabilities		8,558	(6,020)	(515)
Other Assets and Liabilities		(49)		27
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		(37,901)	(67,875)	(67,134)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		(21,979)	64,689	(100,198)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets				66,900
NET CASH (USED) PROVIDED BY INVESTING ACTIVITIES		(21,979)	64,689	(33,298)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		217,000	71,400	193,500
Repayments of Long-Term Debt and Lines of Credit		(145,170)	(65,230)	(82,000)
Debt Issuance Costs		(10,754)	(2,983)	(1,411)
Dividends Paid on Preferred Stock		(1,196)		(9,660)
NET CASH PROVIDED BY FINANCING ACTIVITIES		59,880	3,187	100,429
NET INCREASE IN CASH		0	1	(3)
CASH AND CASH EQUIVALENTS – BEGINNING		3	2	5
CASH AND CASH EQUIVALENTS – ENDING	$ 3	$ 3	$ 3	$ 2

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) $ in Thousands	Mar. 23, 2018USD ($)	Mar. 21, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 13, 2018Well	Jan. 01, 2018Well
Subsequent Event [Line Items]
Loss on disposal of assets				$ 1,428	$ 4,121	$ 540
Subsequent Event | RW Gathering, LLC
Subsequent Event [Line Items]
Membership interest sold								40.00%
Total consideration for the transactions		$ 17,200
Proceeds received from the transactions	$ 16,400
Amount held in escrow	$ 200
Loss on disposal of assets			$ (600)
Subsequent Event | Pennsylvania
Subsequent Event [Line Items]
Number of non-operated oil and gas wells sold | Well							61	61