Rex Energy 10-K 15 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 02, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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		98,013,126
Entity Public Float			$ 46,993,210

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents		$ 3,697	$ 1,091
Accounts Receivable		25,448	17,274
Taxes Receivable		211	18
Short-Term Derivative Instruments		1,873	34,260
Inventory, Prepaid Expenses and Other		2,546	3,059
Assets Held for Sale			53,151
Total Current Assets		33,775	108,853
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,053,461	943,092
Unevaluated Oil and Gas Properties		215,794	262,992
Other Property and Equipment		21,401	20,363
Wells and Facilities in Progress		21,964	141,100
Pipelines		18,029	14,024
Total Property and Equipment		1,330,649	1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(475,205)	(430,528)
Net Property and Equipment		855,444	951,043
Other Assets		2,492	2,501
Long-Term Derivative Instruments		2,212	9,534
Total Assets		893,923	1,071,931
Current Liabilities
Accounts Payable		40,712	36,785
Current Maturities of Long-Term Debt		764	402
Accrued Liabilities		37,207	40,608
Short-Term Derivative Instruments		25,025	2,486
Liabilities Related to Assets Held for Sale			36,320
Total Current Liabilities		103,708	116,601
Noncurrent Liabilities
Long-Term Derivative Instruments		7,227	5,556
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		113,785	109,386
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges	[1]	641,762	663,089
Premium (Discount) on Senior Notes, Net		(3,601)	2,344
Other Long-Term Debt		3,409
Other Deposits and Liabilities		8,671	3,156
Future Abandonment Cost		8,736	11,568
Total Liabilities		883,697	911,700
Commitments and Contingencies (See Note 7)
Stockholders’ Equity
Preferred Stock		1	1
Common Stock		95	54
Additional Paid-In Capital		650,584	623,863
Accumulated Deficit		(640,454)	(463,687)
Total Stockholders’ Equity		10,226	160,231
Total Liabilities and Stockholders’ Equity		$ 893,923	$ 1,071,931
[1]	Includes unamortized debt issuance and financing costs of approximately ($7.9) million and $11.9 million as of December 31, 2016 and 2015, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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	16,100
Preferred Stock, shares outstanding	3,987	16,100
Common Stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	97,870,608	55,741,229
Common Stock, shares outstanding	97,870,608	55,741,229

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales									$ 139,000		$ 138,707		$ 225,511
Other Revenue									17		42		118
TOTAL OPERATING REVENUE	$ 48,027	$ 34,039	$ 31,265	$ 25,686	$ 27,375	$ 29,656	$ 35,784	$ 45,934	139,017		138,749		225,629
OPERATING EXPENSES
Production and Lease Operating Expense									104,699		93,892		69,547
General and Administrative Expense									20,621		26,694		31,917
(Gain) Loss on Disposal of Assets									(4,121)		(540)		218
Impairment Expense	29,276	9,563	25,139	10,641	73,364	85,193	117,839	6,848	74,619		283,244		20,225
Exploration Expense									2,178		2,617		6,813
Depreciation, Depletion, Amortization and Accretion									62,874		85,844		65,817
Other Operating Expense									10,754		5,603		312
TOTAL OPERATING EXPENSES									271,624		497,354		194,849
INCOME (LOSS) FROM OPERATIONS									(132,607)		(358,605)		30,780
OTHER INCOME (EXPENSE)
Interest Expense									(43,519)		(47,783)		(36,945)
Gain (Loss) on Derivatives, Net									(32,515)		60,176		38,876
Other Income (Expense)									(2,124)		(129)		73
Debt Exchange Expense									(9,063)
Gain on Extinguishments of Debt									24,627
Loss on Equity Method Investments											(411)		(813)
TOTAL OTHER INCOME (EXPENSE)									(62,594)		11,853		1,191
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(195,201)		(346,752)		31,971
Income Tax Expense									(2,436)		(6,030)		(15,460)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(75,598)	(16,477)	(52,911)	(52,651)	(97,556)	(88,891)	(151,342)	(14,993)	(197,637)		(352,782)		16,511
Income (Loss) From Discontinued Operations, Net of Income Taxes									20,922		(8,251)		(59,161)
NET LOSS					(98,037)	(94,676)	(151,803)	(16,517)	(176,715)		(361,033)		(42,650)
Net Income Attributable to Noncontrolling Interests						(1)	949	1,297			2,245		4,039
NET LOSS ATTRIBUTABLE TO REX ENERGY	(67,395)	5,415	(54,594)	(60,141)	(98,037)	(94,675)	(152,752)	(17,814)	(176,715)		(363,278)		(46,689)
Preferred Stock Dividends	(650)	(613)	(1,723)	(2,105)	(2,415)	(2,415)	(2,415)	(2,415)	(5,091)		(9,660)		(2,335)
Effect of Preferred Stock Conversions	668		72,316						72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	$ (100,452)	$ (97,090)	$ (155,167)	$ (20,229)	$ (108,822)		$ (372,938)		$ (49,024)
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$ (0.78)	$ (0.19)	$ 0.24	$ (0.98)	$ (1.84)	$ (1.69)	$ (2.84)	$ (0.32)	$ (1.63)	[1]	$ (6.66)	[1]	$ 0.27	[1]
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders	0.08	0.24	(0.02)	(0.13)	(0.01)	(0.11)	(0.03)	(0.05)	0.26	[1]	(0.19)	[1]	(1.19)	[1]
Basic – Net Loss Attributable to Rex Energy Common Shareholders	$ (0.69)	$ 0.05	$ 0.22	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.37)	[1]	$ (6.85)	[1]	$ (0.92)	[1]
Basic – Weighted Average Shares of Common Stock Outstanding	97,398	90,803	71,804	56,003	54,342	53,936	54,118	54,370	79,256		54,392		53,150
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$ (0.78)	$ (0.19)	$ 0.24	$ (0.98)	$ (1.84)	$ (1.69)	$ (2.84)	$ (0.32)	$ (1.63)	[1]	$ (6.66)	[1]	$ 0.27	[1]
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders	0.08	0.24	(0.02)	(0.13)	0	(0.11)	(0.03)	(0.05)	0.26	[1]	(0.19)	[1]	(1.19)	[1]
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$ (0.69)	$ 0.05	$ 0.22	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.37)	[1]	$ (6.85)	[1]	$ (0.92)	[1]
Diluted – Weighted Average Shares of Common Stock Outstanding	97,398	90,803	71,804	56,003	54,342	53,936	54,118	54,370	79,256		54,392		53,150
[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 - USD ($) $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit	Rex Energy Stockholders' Equity	Noncontrolling Interest
Balance at Dec. 31, 2013	$ 416,925	$ 54		$ 456,554	$ (41,725)	$ 414,883	$ 2,042
Balance (in shares) at Dec. 31, 2013		54,186,000
Non-Cash Compensation	5,769			5,769		5,769
Issuance of Restricted Stock, Net of Forfeitures (in shares)		(58,000)
Stock Option Exercise	$ 515			515		515
Stock Option Exercise (in shares)	46,526	47,000
Capital Distributions	$ (1,840)						(1,840)
Issuance of stock, net of issuance costs	154,989		$ 1	154,988		154,989
Issuance of stock, net of issuance costs (in shares)			16,000
Dividends Declared on Preferred Stock	(2,335)				(2,335)	(2,335)
Net Income (Loss)	(42,650)				(46,689)	(46,689)	4,039
Balance at Dec. 31, 2014	531,373	$ 54	$ 1	617,826	(90,749)	527,132	4,241
Balance (in shares) at Dec. 31, 2014		54,175,000	16,000
Non-Cash Compensation	$ 6,469			6,469		6,469
Issuance of Restricted Stock, Net of Forfeitures (in shares)		1,566,000
Stock Option Exercise (in shares)	0
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	$ 54	$ 1	623,863	(463,687)	160,231
Balance (in shares) at Dec. 31, 2015		55,741,000	16,000
Non-Cash Compensation	2,919			2,919		2,919
Issuance of Common Stock in Debt Exchange	$ 6,412	$ 8		6,404		6,412
Issuance of Common Stock in Debt Exchange (in shares)	8,400,000	8,413,000
Issuance of Common Stock for Debt Extinguishments	$ 17,378	$ 23		17,355		17,378
Issuance of Common Stock for Debt Extinguishments (in shares)		23,523,000
Preferred Stock Dividends settled in Common Shares				52	(52)
Preferred Stock Dividends settled in Common Shares ( in shares)		62,000
Issuance of Restricted Stock, Net of Forfeitures	$ 1	$ 1				1
Issuance of Restricted Stock, Net of Forfeitures (in shares)		820,000
Stock Option Exercise (in shares)	0
Conversion of Preferred Stock to Common Stock		$ 9		(9)
Conversion of Preferred Stock to Common Stock (in shares)		9,312,000	(12,000)
Net Income (Loss)	$ (176,715)				(176,715)	(176,715)
Balance at Dec. 31, 2016	$ 10,226	$ 95	$ 1	$ 650,584	$ (640,454)	$ 10,226
Balance (in shares) at Dec. 31, 2016		97,871,000	4,000

Consolidated Statements of Cha6

Consolidated Statements of Changes in Noncontrolling Interests and Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement Of Stockholders Equity [Abstract]
Dividend declared, per preferred share	$ 600	$ 145

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ (176,715)	$ (361,033)	$ (42,650)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Loss on Equity Method Investments		411	813
Non-cash Expenses	24,124	7,649	6,789
Depreciation, Depletion, Amortization and Accretion	67,975	104,822	98,171
(Gain) Loss on Derivatives	32,515	(60,176)	(38,876)
Cash Settlements of Derivatives	32,571	55,793	7,281
Dry Hole Expense	905	330	4,064
Deferred Income Tax Benefit			(25,992)
Impairment Expense	78,162	345,775	132,684
Gain on Extinguishment of Debt	(24,627)
(Gain) Loss on Disposal of Assets	(34,651)	(521)	589
Gain on Sale of Water Solutions		(57,778)
Changes in operating assets and liabilities
Accounts Receivable	(6,414)	21,679	(13,620)
Inventory, Prepaid Expenses and Other Assets	906	(568)	(1,359)
Accounts Payable and Accrued Liabilities	2,795	(22,955)	37,274
Other Assets and Liabilities	(1,950)	(2,543)	(2,462)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(4,404)	30,885	162,706
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		58	263
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	40,884	77,226	546
Proceeds from Joint Venture	19,461	16,611
Acquisitions of Undeveloped Acreage	(6,712)	(28,242)	(169,423)
Acquisitions of Oil and Gas Properties and Equipment	(48,982)	(221,099)	(391,422)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	4,651	(155,446)	(560,036)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit	71,400	229,314	209,895
Repayments of Long-Term Debt and Lines of Credit	(65,230)	(108,335)	(263,152)
Repayments of Loans and Other Notes Payable	(828)	(1,519)	(2,721)
Proceeds from Senior Notes, Net of Discounts and Premiums			325,000
Debt Issuance Costs	(2,983)	(1,414)	(6,824)
Proceeds from the Issuance of Preferred Stock, Net			154,988
Proceeds from the Exercise of Stock Options			515
Distributions by the Partners of Consolidated Subsidiary		(830)	(1,840)
Dividends Paid on Preferred Stock		(9,660)	(2,335)
NET CASH PROVIDED BY FINANCING ACTIVITIES	2,359	107,556	413,526
NET INCREASE (DECREASE) IN CASH	2,606	(17,005)	16,196
CASH AND CASH EQUIVALENTS – BEGINNING	1,091	18,096	1,900
CASH AND CASH EQUIVALENTS – ENDING	3,697	1,091	18,096
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	3,697	1,091	17,978
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE			118
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	30,805	47,628	26,874
Cash Paid (Received) for Income Taxes	29	(502)	(4,643)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations	1,346	14,210	41,612
NON-CASH ACTIVITIES
Decrease in Accrued Liabilities for Capital Expenditures	712	$ (11,703)	$ 3,477
Decrease in Senior Notes, Net of Issuance Costs due to Debt to Equity Conversions	(47,182)
Decrease in Bond Interest Payable due to Debt to Equity Conversions	(892)
Increase in Common Stock outstanding due to Debt to Equity Conversions	17,378
Illinois Basin Operations
NON-CASH ACTIVITIES
Fair value of contingent consideration receivable - sale of Illinois Basin	$ (2,936)

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	12 Months Ended
	Dec. 31, 2016
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. For purposes of compliance with Accounting Standards Update (“ASU”) 2015-3, which we adopted on January 1, 2016, we have reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and approximately $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. In addition, we adopted ASU 2015-17 on January 1, 2016, which eliminates the need to show deferred tax liabilities and assets as current and noncurrent. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero (see Recent Accounting Pronouncements Summary of Significant Accounting Policies Our revolving credit facility 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. In order to improve our liquidity positions to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, and may require the consent of one or more third parties, including one or more of the following (i) refinancing of existing debt, (ii) debt-for-debt or debt-for-equity exchanges, (iii) joint venture opportunities, (iv) minimizing capital expenditures, (v) improving cash flows from operations, (vi) effectively managing working capital, (vii) adding hedging positions, (viii) asset sales, and (ix) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations. 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 years ended December 31, 2015 and 2014. As of December 31, 2016 and 2015, 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 assets and liabilities of our Illinois Basin operations have been classified as Held for Sale in the accompanying Consolidated Balance Sheets as of December 31, 2015 and the results of operations of our Illinois Basin operations have been classified as Discontinued Operations in the accompanying Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016, we have a derivative asset of $2.9 million recorded, 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, 2016
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 oil, NGL and natural gas 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, 2016 and 2015, our Cash and Cash Equivalents consisted of only cash. Accounts Receivable Our trade accounts receivable, which are primarily from condensate, NGLs and natural gas 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, 2016 and 2015 were $0.1 million and $0.2 million, respectively. To the extent actual quantities and values of condensate, NGLs and natural gas 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, 2016, we carried approximately $22.2 million in production receivable, of which approximately $17.5 million were production receivables due from our three largest purchasers. Inventory Inventory is valued at the lower of cost or market value and consists of our ownership interest in condensate and NGLs held in terminal tanks located in the field. Condensate and NGL 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. Oil, NGL and Natural Gas Property, Depreciation and Depletion We account for oil, NGL and natural gas 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 proved 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, 2016, 2015 and 2014, we capitalized interest costs of $2.7 million, $7.7 million and $7.3 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 oil and natural gas 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 oil, NGL and natural gas 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 oil and gas 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 oil, NGL and natural gas 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 $74.6 million, $283.2 million and $20.2 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2016, 2015 and 2014, 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, 2016 and 2015, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated 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 condensate, NGL and natural gas 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 engineer estimates 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, 2016, 2015 and 2014 totaled approximately $1.0 million, $1.0 million and $0.7 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2016 and 2015, approximately $1.1 million December 31, 2016 (in thousands) December 31, 2015 (in thousands) Beginning Balance $ 11,934 $ 8,061 Asset Retirement Obligation Incurred 575 1,063 Asset Retirement Obligation Settled (671 ) (449 ) Asset Retirement Obligation Cancelled or Sold Properties (4,876 ) (136 ) Asset Retirement Obligation Revision of Estimated Obligation 1,918 2,428 Asset Retirement Obligation Accretion Expense 985 967 Total Future Abandonment Costs $ 9,865 $ 11,934 Revenue Recognition Condensate, NGL and natural gas revenue is recognized when the condensate, NGL or natural gas 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 and NGL sales, title is transferred to the purchaser when the condensate or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of condensate, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for condensate, NGLs and natural gas 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. The point of sale for our condensate, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for condensate and NGL production held in stock tanks before delivery to the purchaser. To the extent actual quantities and values of condensate, NGLs and natural gas 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 Natural Gas, NGL and Condensate Sales on the Statements of Operations. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) Derivative Instruments We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of condensate, natural gas and NGLs. 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 2016, 2015 and 2014 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 oil, natural gas and NGL 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 . Employee Benefit and Equity Plans, In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting We elected to early adopt ASU 2016-09 effective January 1, 2016. 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, 2016, we had 97,870,608 common shares outstanding, 1,181,100 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 2,427,494 restricted stock awards, of which approximately 617,479 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share Recent Accounting Pronouncements In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs We adopted this ASU on January 1, 2016. In conjunction with the adoption of ASU 2015-03, we reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and $ Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. Adoption did not have an impact on Net Income or Accumulated Deficit. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. An entity should apply the amendments in this ASU using one of the following two methods: 1) Retrospectively to each prior reporting period presented. 2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes 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 March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting We elected to early adopt ASU 2016-09 effective January 1, 2016 utilizing a modified retrospective approach. An income tax benefit of approximately $1.3 million representing previously unrecognized tax benefits originating from our deferred compensation plans was recognized as of January 1, 2016 through a cumulative adjustment to retained earnings. As the deferred tax asset generated by the cumulative effect adjustment was subject to a full valuation allowance, there is no cumulative effect to retained earnings as a result of the adoption of ASU 2016-09. With the adoption of ASU 2016-09 we are electing to continue our current process of estimating the number of forfeitures of equity based awards in accounting for our deferred compensation plans. As such, this election has no cumulative effect on retained earnings. We have elected to present the cash flow statement on a prospective transition method and no prior periods have been adjusted. As required by ASU 2016-09, we have adjusted our earnings per share calculation model to exclude the tax effect of any anticipated windfall benefits or shortfalls, when projecting proceeds available for share repurchases. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments . The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues: • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

Business and Oil and Gas Proper

Business and Oil and Gas Property Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2016
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 Holdings, LLC and its subsidiaries (“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. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us, leaving ArcLight with a 17.5% working interest. 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 20 of these additional wells. We expect total consideration for this transaction to be $175.0 million with approximately $126.1 million committed as of December 31, 2016. BSP has paid approximately $82.4 million for their interest in elected wells as of December 31, 2016. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of December 31, 2016, 30 of the 42 committed wells were in line and producing, eight wells were drilled and awaiting completion and four wells were in progress of being drilled. 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 and received the additional proceeds of approximately $38.5 million at closing in August. 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. No proceeds were received for the quarter ending December 31, 2016, as WTI prices did not meet the necessary threshold. For additional information, see Note 10, Fair Value of Financial Instruments and Derivative Instruments Calendar Quarter Ending West Texas Intermediate Average Price per Bbl 3/31/2017 $ 56.25 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (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.

Discontinued Operations_Assets

Discontinued Operations/Assets Held For Sale	12 Months Ended
	Dec. 31, 2016
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, we sold Water Solutions pursuant to a purchase and sale agreement with American Water. As of December 31, 2016 and 2015, 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) 2016 2015 2014 Revenues: Field Services Revenue $ — $ 33,086 $ 58,627 Total Operating Revenue — 33,086 58,627 Costs and Expenses: General and Administrative Expense — 1,961 4,081 Depreciation, Depletion, Amortization and Accretion — 78 3,703 Impairment Expense — — 67 Field Service Operating Expense — 25,981 44,369 Gain on Disposal of Asset — (44 ) (55 ) Interest Expense — 487 628 Other (Income) Expense — (57,589 ) 66 Total Costs and Expenses (Income) — (29,126 ) 52,859 Income from Discontinued Operations Before Income Taxes — 62,212 5,768 Income Tax Expense — (24,227 ) (768 ) Income from Discontinued Operations, net of taxes — $ 37,985 $ 5,000 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. The carrying value of assets and liabilities of our Illinois Basin operations that are classified as Held for Sale in the accompanying Consolidated Balance Sheets at December 31, 2015 are as follows: December 31, ($ in Thousands) 2015 Assets: Accounts Receivable $ 2,209 Inventory, Prepaid Expenses and Other 770 Total Current Assets 2,979 Evaluated Oil & Gas Properties 296,338 Other Property and Equipment, Net 19,749 Wells and Facilities in Progress 3,456 Accumulated Depreciation, Depletion, and Amortization (269,371 ) Total Long-Term Assets 50,172 Total Assets Held for Sale $ 53,151 Liabilities: Accounts Payable 1,089 Current Maturities of Long-Term Debt 188 Accrued Liabilities 3,718 Total Current Liabilities 4,995 Long-Term Debt 10 Future Abandonment Cost 31,315 Total Long-Term Liabilities 31,325 Total Liabilities Related to Assets Held for Sale $ 36,320 Net Assets Held for Sale: $ 16,831 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, 2016, 2015, and 2014. December 31, ($ in Thousands) 2016 2015 2014 Revenues: Oil Sales $ 11,282 $ 33,244 $ 72,359 Total Operating Revenue 11,282 33,244 72,359 Costs and Expenses: Production and Lease Operating Expense 11,033 25,099 30,556 General and Administrative Expense 1,002 2,741 4,219 (Gain) Loss on Disposal of Assets (30,530 ) 63 426 Impairment Expense 3,543 62,531 112,394 Exploration Expense 143 394 2,633 Depreciation, Depletion, Amortization and Accretion 5,100 18,900 28,650 Interest Expense 4 23 32 Other (Income) Expense 65 (14 ) (16 ) Total Costs and Expenses (9,640 ) 109,737 178,894 Income (Loss) from Discontinued Operations Before Income Taxes 20,922 (76,493 ) (106,535 ) Income Tax Benefit — 30,257 42,374 Income (Loss) from Discontinued Operations, net of taxes $ 20,922 $ (46,236 ) $ (64,161 ) Production: Crude Oil (Bbls) 310,388 729,251 806,162

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2016
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 own 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. 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, 2016
Risks And Uncertainties [Abstract]
Concentrations of Credit Risk	6. CONCENTRATIONS OF CREDIT RISK At times during the years ended December 31, 2016 and 2015, 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 six high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our senior credit 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, 2016, we carried approximately $22.2 million in production receivables, of which approximately $17.5 million were production receivables due from three purchasers.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
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. As of December 31, 2016 and 2015, we did not have any reserves established for future legal obligations. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we currently believe that no reserve is needed, 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 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 future losses that are not currently accrued. Based on currently available information, we believe that it is remote that future costs, if any, 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 might be 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, 2016 and 2015, we had posted $46.5 million and $41.0 million, respectively, in various letters of credit to secure our drilling and related operations. Approximately $46.0 million of the letters of credit outstanding at December 31, 2016 are related to firm natural gas transportation agreements. Lease Commitments At December 31, 2016 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.9 million, $1.0 million and $0.8 million for the years ended December 31, 2016, 2015 and 2014, respectively. Lease commitments by year for each of the next five years are presented in the table below. ($ in Thousands) 2017 $ 997 2018 565 2019 563 2020 422 2021 — Thereafter — Total $ 2,547 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 $16.3 million in 2017, $16.3 million in 2018, $16.3 million in 2019, $16.4 million in 2020, $16.3 million in 2021 and $80.4 million thereafter, assuming our average working interest in the region of approximately 52.4%. 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 $2.7 million in 2017 and $1.8 million in 2018, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations for the year ended December 31, 2015. Approximately $2.5 million of this amount was paid in January 2015 and $2.3 million of this amount was paid in January 2016. 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 $402.4 million. For the years ended December 31, 2016, 2015 and 2014, we incurred expenses related to the transportation, processing and marketing our condensate, natural gas and natural gas liquids of approximately $91.7 million, Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2017 $ 43,260 2018 46,685 2019 47,721 2020 46,413 2021 43,459 Thereafter 481,821 Total $ 709,359 Pennsylvania Impact Fee In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee will 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. The fee for each unconventional natural gas well is determined using the following matrix with vertical unconventional natural gas wells being charged 20%: <$2.25(a) $2.26 - $2.99(a) $3.00 - $4.99(a) $5.00 - $5.99(a) >$5.99(a) Year One $ 40,200 $ 45,300 $ 50,300 $ 55,300 $ 60,400 Year Two $ 30,200 $ 35,200 $ 40,200 $ 45,300 $ 55,300 Year Three $ 25,200 $ 30,200 $ 30,200 $ 40,200 $ 50,300 Year 4 – 10 $ 10,100 $ 15,100 $ 20,100 $ 20,100 $ 20,100 Year 11 – 15 $ 5,000 $ 5,000 $ 10,100 $ 10,100 $ 10,100 (a) Pricing utilized for determining annual fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the year ending December 31. For the years ended December 31, 2016, 2015 and 2014, we incurred approximately $3.0 million, .

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
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, 2016, we did not pay Charlie Brown for use of the aircraft. For each of the years ended December 31, 2015 and 2014 we paid Charlie Brown approximately $0.1 million 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. Charlie Brown II has a loan from Graystone Bank to purchase the aircraft that was originally $1.5 million at its inception in June 2007. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan required payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II has been required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The company and Shaner Hotel each guarantee up to fifty percent, or $0.8 million, of the principal balance of the loan. The balance of this loan as of December 31, 2016 and 2015 was approximately $0.9 million and $1.0 million, respectively. For the years ended December 31, 2016, 2015 and 2014, we paid Charlie Brown II approximately $0.2 million, $0.3 million and $0.2 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. As of December 31, 2016, there were negligible amounts due to or from us to any Shaner affiliated entities. 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 amount of $35,000 which began on April 1, 2013 and end on December 31, 2017, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The term of the lease may be extended for up to three five-year extensions or the property may be purchased outright by our exercise of a purchase option at the end of the initial five-year lease term. For the year 2016, 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. RW Gathering, LLC We own a 40% interest in RW Gathering which owns gas-gathering assets to 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 and $20.1 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) and 2014, respectively. Of the amounts incurred, we eliminated approximately $4.7 million and $16.2 million in consolidation for the years 2015 and 2014, respectively. As of December 31, 2015, we had no payables owed to Water Solutions for work performed during the periods 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, 2016
Debt Disclosure [Abstract]
Long-Term Debt	9. LONG-TERM DEBT Senior Credit Facility We maintain a revolving credit facility, evidenced by a credit agreement dated March 27, 2013 and most recently updated on July 1, 2016 (the “Senior Credit Facility”) with Royal Bank of Canada, as Administrative Agent and lenders from time to time parties thereto. Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. As of December 31, 2016, the borrowing base under the Senior Credit Facility was $190.0 million. The borrowing base under the Senior Credit Facility may be increased to up to $400.0 Subsequent Events The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition or divestiture of proved developed producing oil and gas reserves with a purchase or sale price for such reserves greater than 10% of the then borrowing base. Our next scheduled redetermination will occur on or about April 1, 2017. As of December 31, 2016, loans made under the Senior Credit Facility were set to mature on September 12, 2019. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. Subsequent to our February 3, 2016 amendment, and at our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” or the “Alternate Base Rate,” plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of (i) the rate per annum as determined by the administrative agent by reference to the rate set by ICE Benchmark Administration for deposits in dollars for a period equal to the applicable interest period (the “LIBO Rate”), multiplied by (ii) the statutory reserve rate. The Alternate Base Rate is equal to the greatest of (a) Royal Bank of Canada’s prime rate in effect at its principal office in Toronto, Canada, (b) the weighted average of the rates on overnight Federal funds transactions published on the next succeeding business day by the Federal Reserve Bank of New York (the “Federal Funds Effective Rate”), plus 0.5%, and (c) the Adjusted LIBO Rate for a one month interest period plus 1.0%. The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 225 to 325 basis points, and in the case of loans bearing interest at the Alternate Base Rate, ranges from 125 to 225 basis points, in each case, determined based upon our borrowing base utilization at such date of determination. Upon the occurrence and continuance of an event of default, all outstanding loans shall bear interest at a per annum rate equal to 200 basis points plus the then effective rate of interest. Interest is payable on the last day of each applicable interest period. Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. As of December 31, 2016, we were in compliance with these swap agreement restrictions. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million or 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate. The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; 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 (for further information, see Note 2, Summary of Significant Accounting Policies Concentrations of Credit Risk Fair Value of Financial Instruments and Derivative Instruments The Senior Credit Facility requires we meet certain financial requirements, on a quarterly basis, including a minimum consolidated current ratio, a maximum “Net Senior Secured Debt” to EBITDAX ratio and minimum “Total PDP PV-9” to net senior secured debt ratio (all terms in quotations as defined in the Senior Credit Facility). EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, including our . In order to improve our liquidity positions to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, and may require the consent of one or more third parties, including one or more of the following (i) refinancing of existing debt, (ii) debt-for-debt or debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing capital expenditures, (iv) improving cash flows from operations, (v) effectively managing working capital, (vi) adding hedging positions, (vii) asset sales, and (viii) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity will be raised from any transactions or that any such transactions can or will be consummated within the period needed to meet our obligations. 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 Senior Secured Second Lien Notes (the “New Notes”) and (ii) an aggregate of 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the Exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. The effective interest rate of the New Notes is 6.06% compared to the stated initial rate of 1.0%, increasing to 8.0% effective April 1, 2018. 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 New Notes and (ii) an aggregate of 8.4 million shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept Shares. In addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. 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. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, commencing with the payment due April 1, 2018, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $9.1 million in third-party debt issuance costs for the year ended December 31, 2016. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations. Following the completion of the Exchange, we entered into debt-for-equity exchanges with certain holders of our Existing Notes, as well as holders or our New Notes. In all cases we accounted for the exchanges as troubled debt restructurings. We completed an exchange with a single holder representing a troubled debt restructuring with a modification of terms, wherein the holder exchanged a portion of their notes for a privately negotiated amount of our common shares. $43.5 million of our New Notes were tendered and subsequently cancelled, in exchange for common shares with a fair value of $10.9 million. As the future undiscounted cash flows of the holder’s remaining New Notes was greater than our carrying amount of the debt, no gain was recognized. We have reduced the principal amount of the New Notes outstanding by the fair value of the equity given in the exchange, and a new interest rate has been established. The effective interest rate of the remaining notes outstanding due to this holder is 1.16%, compared to the stated rate of 1.0%, and increasing to 8.0% effective April 1, 2018. We completed exchanges with several holders of our Existing Notes and our New Notes, which were accounted for as troubled debt restructurings, with full extinguishment of debt. $28.7 million in aggregate principal amount of our remaining Existing Notes and $2.2 million in aggregate principal of our outstanding New Notes, in exchange for the issuance of an aggregate of approximately 13.2 million shares of our unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the Company for the year ended December 31, 2016 of $24.6 million, or $0.25 per common share, presented as Gain on Extinguishments of Debt in our Consolidated Statement of Operations. We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Existing Notes and New Notes from the holders. Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets. Our Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise. For additional information on our guarantor and non-guarantor subsidiaries, see Note 25, Condensed Consolidating Financial Information As of December 31, 2016, we had approximately $638.2 million of Senior Notes outstanding, which is inclusive of a net discount of $3.6 million and deferred financing costs of $15.9 million. As of December 31, 2015, we had approximately $677.3 million of Senior Notes outstanding, which is inclusive of a net premium of $2.3 million and deferred financing costs of $15.3 million. The amortization of our net discount in 2016 and net premium in 2015, which follows the effective interest method, resulted in reductions to our interest expense for 2016 and 2015, of approximately $5.2 million and $0.4 million, respectively. Each series of the Senior Notes are governed by an indenture (collectively, the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on the 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 sell substantially all of its 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 the 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 to1.00. As of December 31, 2016, the Company’s Fixed Charge Coverage Ratio was 1.02 to 1.00. We expect our Fixed Charge Coverage Ratio to improve based on our projections of decreased interest expense related to the New Notes. As of December 31, 2016, we were limited to incurring an additional $166.3 million in additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual Trustees or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at December 31, 2016 and December 31, 2015: ($ in Thousands) December 31, 2016 December 31, 2015 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges(b) $ 641,762 $ 663,089 Premium (Discount) on Senior Notes, Net (3,601 ) 2,344 Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs (a)(c) 113,785 109,386 Capital Leases and Other Obligations (a) 4,173 419 Total Debt 756,119 775,238 Less Current Portion of Long-Term Debt (764 ) (402 ) Total Long-Term Debt $ 755,355 $ 774,836 (a) The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2016, 2015 and 2014 was approximately 3.8%, 1.7 % and 2.2%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2016, 2015 and 2014 was approximately 12.6%, 5.5% and 4.0%, respectively (b) Includes unamortized debt issuance and financing costs of approximately ($7.9) million and $11.9 million as of December 31, 2016 and 2015, respectively. (c) Includes unamortized debt issuance costs of approximately $3.9 million and $2.1 million as of December 31, 2016 and 2015, respectively. . The following is the principal maturity schedule for total debt outstanding as of December 31, 2016: ($ in thousands) 2017 $ 764 2018 807 2019 118,614 2020 596,633 2021 554 Thereafter 5,649 Total 1 $ 723,021 1 Does not include $3.6 million net discount on Senior Notes, $32.7 million of unamortized deferred gain on debt exchanges or ($4.0) million of amortization of deferred financing costs.

Fair Value Of Financial Instrum

Fair Value Of Financial Instruments And Derivative Instruments	12 Months Ended
	Dec. 31, 2016
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, Oil and NGL 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 oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of December 31, 2016, 2015 and 2014, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net 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. Swaption agreements provide options to counterparties to extend swaps into subsequent years. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. 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 six 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 received net cash settlements of $32.6 million, $54.9 million and $6.0 million in relation to our commodity derivatives for the years ended December 31, 2016, 2015 and 2014 respectively. As of December 31, 2016, we had over 65.0% of our 2016 condensate production volumes hedged through 2017, over 75.0% of our 2016 natural gas production volumes hedged through 2017 and over 50.0% of our 2016 NGL production volumes hedged through 2017. Including the effects of derivatives added since December 31, 2016, of our 2016 natural gas production over 80.0% is hedged through 2017 and over 60.0% of our 2016 NGL production hedged through 2017. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future development or the natural decline of our condensate, NGL and gas production. Contingent Consideration – Sale of Illinois Basin Operations In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets, as defined in the contract, are achieved at specified future dates (see Note 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, 2016, we had approximately $117.7 million in borrowings outstanding under our Senior Credit Facility, which is subject to variable rates of interest, and had $601.2 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 and 2014, however there were no arrangements in place as of December 31, 2016 and 2015. 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 years ended December 31, 2015 and 2014, we received cash payments of approximately $0.9 million and $1.3 million, respectively, related to our interest rate swaps. The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014: For the Year Ended December 31, ($ in Thousands) 2016 2015 2014 Oil $ (1,515 ) $ 7,132 $ 8,613 Natural Gas (15,036 ) 37,647 18,406 NGLs (17,788 ) 14,839 10,340 Interest Rate — 934 1,517 Refined Products 54 (376 ) — Contingent Consideration 1,770 — — Gain (Loss) on Derivatives, Net $ (32,515 ) $ 60,176 $ 38,876 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 $28.2 million as of December 31, 2016, and a net asset of $35.8 million at December 31, 2015. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2016 consisted of the following: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2017 - Deferred Premium Put 15,000 Bbls $ — $ 51.00 $ — $ — $ (9 ) 2017 - Swaps 81,000 Bbls — — — 53.30 (220 ) 2017 - Collars 48,000 Bbls — 45.00 57.20 — (86 ) 2017 - Three-Way Collars 93,000 Bbls 40.16 49.68 61.50 — (132 ) 2018 - Swaps 60,000 Bbls — — — 54.00 (146 ) 2018 - Three-Way Collars 60,000 Bbls 43.00 52.00 62.30 — (58 ) 357,000 Bbls $ (651 ) Natural Gas 2017 - Swaps 11,000,000 Mcf $ — $ — $ — $ 3.11 $ (4,468 ) 2017 - Swaptions — Mcf — — — 3.15 (1,258 ) 2017 - Cap Swaps 3,900,000 Mcf 2.35 — — 2.81 (3,303 ) 2017 - Three-Way Collars 17,510,000 Mcf 2.33 3.01 3.87 — (2,246 ) 2017 - Calls 3,000,000 Mcf — — 3.64 — (1,478 ) 2017 - Basis Swaps - Dominion South 14,745,000 Mcf — — — (0.86 ) (53 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (355 ) 2017 - Collars 1,700,000 Mcf — 2.54 3.20 — (873 ) 2018 - Swaps 5,510,000 Mcf — — — 3.25 (797 ) 2018 - Swaptions — Mcf — — — 3.15 (167 ) 2018 - Collars 450,000 Mcf — 3.20 3.65 — (115 ) 2018 - Three-Way Collars 8,775,000 Mcf 2.30 2.89 3.58 — (1,786 ) 2018 - Basis Swaps - Dominion South 16,242,500 Mcf — — — (0.82 ) (193 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (355 ) 2018 - Calls 5,810,000 Mcf — — 3.97 — (491 ) 2019 - Basis Swaps - Dominion South 16,242,500 Mcf — — — (0.81 ) (230 ) 2020 - Basis Swaps - Dominion South 13,542,000 Mcf — — — (0.80 ) (189 ) 147,627,000 Mcf $ (18,357 ) NGLs 2017 C3 + NGL Swaps 1,337,000 Bbls $ — $ — $ — $ 28.14 $ (8,197 ) 2017 Ethane Swaps 840,000 Bbls — — — 10.50 (1,698 ) 2018 C3 + NGL Swaps 852,000 Bbls — — — 28.98 (2,082 ) 2018 Ethane Swaps 300,000 Bbls — — — 13.02 (118 ) 3,329,000 Bbls $ (12,095 ) The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015 is summarized below. December 31, December 31, ($ in Thousands) 2016 2015 Short-Term Derivative Assets: Crude Oil—Collars $ — $ 1,078 Crude Oil—Deferred Put Spread — 852 Crude Oil—Three-Way Collars — 577 NGL—Swaps — 10,250 Natural Gas—Swaps 206 9,010 Natural Gas—Cap Swaps 61 1,977 Natural Gas—Basis Swaps 232 70 Natural Gas—Three-Way Collars 151 6,183 Natural Gas—Collars — 1,728 Natural Gas—Swaption — 798 Natural Gas—Put Spread — 1,737 Contingent Consideration - Sale of Illinois Basin 1,223 — Total Short-Term Derivative Assets $ 1,873 $ 34,260 Long-Term Derivative Assets: NGL—Swaps $ — $ 344 Natural Gas—Cap Swaps — 2,294 Natural Gas—Swaps 206 1,593 Natural Gas—Basis Swaps 293 195 Natural Gas—Three-Way Collars — 5,108 Contingent Consideration - Sale of Illinois Basin 1,713 — Total Long-Term Derivative Assets $ 2,212 $ 9,534 Total Derivative Assets $ 4,085 $ 43,794 Short-Term Derivative Liabilities: Refined Product —Swaps — (376 ) Crude Oil—Collars (86 ) — Crude Oil—Deferred Premium Put (9 ) — Crude Oil—Three-Way Collars (132 ) — Crude Oil—Swaps (220 ) — NGL—Swaps (9,895 ) — Natural Gas—Three-Way Collars (2,397 ) (31 ) Natural Gas—Cap Swaps (3,364 ) — Natural Gas—Collars (873 ) — Natural Gas—Basis Swaps (640 ) (1,585 ) Natural Gas—Call (1,478 ) — Natural Gas—Swaption (1,258 ) (202 ) Natural Gas—Swaps (4,673 ) (292 ) Total Short - Term Derivative Liabilities $ (25,025 ) $ (2,486 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars (58 ) — Crude Oil—Swaps (146 ) — NGL—Swaps (2,200 ) — Natural Gas—Swaps (1,004 ) — Natural Gas—Collars (115 ) — Natural Gas—Swaption (167 ) (297 ) Natural Gas—Basis Swaps (1,260 ) (4,186 ) Natural Gas—Call (491 ) (989 ) Natural Gas—Three-Way Collars (1,786 ) (84 ) Total Long-Term Derivative Liabilities $ (7,227 ) $ (5,556 ) Total Derivative Liabilities $ (32,252 ) $ (8,042 ) Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of December 31, 2016 and 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. Our Level 3 fair value measurements have been historically comprised of our natural gas basis swap contracts. As of December 31, 2016, these fair values transferred to Level 2 based on the observability of the inputs in calculating the fair value. Basis differential markets have become more heavily traded thus allowing the observable inputs to extend the full term of our contracts. The fair values recorded as of December 31, 2015 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of December 31, 2015 are included in the table below. As of December 31, 2015 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.27) - ($1.08) $ (0.74 ) $ (5,468 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.05) - ($0.17) $ (0.12 ) $ (38 ) 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, 2016 and 2015, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: 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 ) $ — Fair Value Measurements at December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 ) 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, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, 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, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of December 31, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments. The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2016 and 2015 (in thousands): For the Year Ended December 31, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value 7,249 (2,548 ) Transfers out of Level 3 (1,564 ) — Purchases — — Settlements Received (179 ) (4,299 ) Ending Balance of Level 3 $ — $ (5,506 ) Changes in fair value on our Level 3 commodity derivative contracts outstanding for the years ended December 31, 2016 and 2015, resulted in an increase of approximately $7.2 million and a decrease of approximately $2.5 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. Asset Retirement Obligations We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: December 31, 2016 December 31, 2015 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 641,762 $ 147,605 $ 663,089 $ 137,402 Secured Lines of Credit 113,785 113,785 109,396 109,396 Capital Leases and Other Obligations 4,173 3,234 419 411 Total $ 759,720 $ 264,624 $ 772,904 $ 247,209 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 We recorded an other than temporary impairment of $74.6 million related to proved properties, unproved properties and other non-revenue producing equipment. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment 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, 2016
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) 2016 2015 2014 Current: Federal $ 1,839 $ — $ — State 597 — 10 Deferred: Federal — 5,773 13,094 State — 257 2,356 Income Tax Expense $ 2,436 $ 6,030 $ 15,460 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, 2016 Year Ended December 31, 2015 Year Ended December 31, 2014 Income (Loss) from continuing operations before noncontrolling interests and income taxes $ (195,201 ) $ (346,752 ) $ 31,971 Statutory U.S. income tax rate 35.0 % 35.0 % 35.0 % Tax expense recognized using statutory U.S. income tax rate $ (68,320 ) $ (121,363 ) $ 11,190 State income taxes, net of federal income tax benefit (3,632 ) (17,137 ) 1,626 Change in estimated future state rates (400 ) (212 ) (743 ) Permanent differences 2,264 1,784 1,014 Change in valuation allowances 72,784 143,566 2,450 Other (260 ) (608 ) (77 ) Total income tax expense $ 2,436 $ 6,030 $ 15,460 Effective income tax rate -1.25 % -1.74 % 48.4 % 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, 2016 and 2015: For the Years Ended December 31, ($ in Thousands) 2016 2015 (a) Tax effects of temporary differences for: Assets: Asset retirement obligation $ 3,955 $ 17,831 Deferred compensation plans 1,581 3,111 Compensation Accruals 762 767 Unrealized loss on derivatives 11,760 — Tax basis of oil and gas properties in excess of book basis — 8,965 Net operating loss carryforwards 79,531 123,488 Deferred Financing Costs (b) 182,519 — Gas Transportation Capacity Commitments 3,031 — Deferred revenue timing differences 443 969 Organization costs 391 456 Percentage depletion carryforward 2,717 2,673 AMT credits 2,131 292 Timing differences - tax partnerships 1,046 4,166 Other 331 372 Valuation allowances (212,041 ) (148,159 ) (c) Total Deferred Tax Assets net of Valuation Allowances $ 78,157 $ 14,931 Liabilities: Book basis of oil and gas properties in excess of tax basis (77,690 ) — Unrealized gain on derivatives — (14,144 ) Other (467 ) (787 ) Total Deferred Tax Liabilities $ (78,157 ) $ (14,931 ) (a) As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities for the year ended December 31, 2015 does not include $1.3 million of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. (b) Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016. (c) Includes approximately $11.3 million of valuation allowances recorded to offset deferred tax assets attributes of our discontinued operations. 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, 2016, 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 $212.0 million for deferred tax assets for which the company may be unable to realize the tax benefit. For the year ended December 31, 2015, 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 $148.2 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, 2016, we had available unused gross federal net operating loss carryforwards of $152.2 million and gross state net operating loss carryforwards of $416.5 million that may be applied against future taxable income that expire from 2023 through 2036. 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 1 2024 — 2025 — 2026 455 2027 968 2028 — 2029 — 2030 — 2031 1,522 2032 — 2033 12,653 2034 6,241 2035 45,296 2036 12,395 Total 79,531 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, 2016, 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, 2016 and 2015. 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, 2011.

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, 2016, we excluded stock options to purchase 1.2 million shares of our common stock due to our Net Loss from Continuing Operations. For each of the years ended December 31, 2015 and 2014, we excluded stock options to purchase 0.4 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2016, 2015 and 2014, we excluded performance-based restricted stock of 0.6 million shares, 1.1 million shares and 0.8 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) 2016 2015 2014 Numerator: Net Income (Loss) From Continuing Operations $ (197,637 ) $ (352,782 ) $ 16,511 Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests 20,922 (10,496 ) (63,200 ) Less: Preferred Stock Dividends (5,091 ) (9,660 ) (2,335 ) Effect of Preferred Stock Conversions 72,984 — — Net Loss Attributable to Common Shareholders $ (108,822 ) $ (372,938 ) $ (49,024 ) Denominator: Weighted Average Common Shares Outstanding - Basic 79,256 54,392 53,150 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 79,256 54,392 53,150 Earnings per Common Share Attributable to Rex Energy Common Shareholders(a): Basic — Net Income (Loss) From Continuing Operations $ (1.63 ) $ (6.66 ) $ 0.27 — Net Income (Loss) From Discontinued Operations 0.26 (0.19 ) (1.19 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (1.37 ) $ (6.85 ) $ (0.92 ) Diluted — Net Income (Loss) From Continuing Operations $ (1.63 ) $ (6.66 ) $ 0.27 — Net Income (Loss) From Discontinued Operations 0.26 (0.19 ) (1.19 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (1.37 ) $ (6.85 ) $ (0.92 ) (a) All earnings per share amounts are attributable to Rex common shareholders.

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Capital Stock	13. CAPITAL STOCK Common Stock Our common stock is currently traded on The NASDAQ Capital Market under the trading symbol “REXX”. We have authorized capital stock of 200,000,000 shares of common stock and 100,000 shares of preferred stock. As of December 31, 2016 and 2015, we had 97,870,608 and 55,741,229 shares of common stock outstanding, respectively. During the year ended December 31, 2016, we issued approximately 8.4 million shares of our common stock in conjunction with the Exchange completed on March 31, 2016, and approximately 23.5 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, 2016 and 2015, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), issued and outstanding totaled 3,987 and 16,100, respectively. During the year ended December 31, 2016, 12,113 shares of Series A Preferred Stock were converted into an aggregate of approximately 9.3 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. No dividend was declared by our board of directors in 2016. As of December 31, 2016, accumulated dividends in arrears totaled $5.0 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. 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 555.56 shares of our common stock per share (5.5556 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, 2016
Segment Reporting [Abstract]
Major Customers	14. MAJOR CUSTOMERS 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 attributable to three customers with the largest single purchaser accounting for $76.0 million, or 52.0%. For the year ended December 31, 2014, approximately $206.1 million, or 92.2%, of our commodity sales from continuing operations were derived from four customers, with the largest customer being responsible for approximately $96.4 million, or 43.1%, of total commodity sales.

Employee Benefit and Equity Pla

Employee Benefit and Equity Plans	12 Months Ended
	Dec. 31, 2016
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 and were suspended during 2016. Our contributions to the plan attributable to continuing operations were negligible for the year ended December 31, 2016 and were approximately $0.5 million and $0.5 million for the years ended December 31, 2015 and 2014, respectively. 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 5,979,470 shares under the Plan, with 2,385,791 and 1,144,297 still available as of December 31, 2016 and 2015, 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, 2016, we issued 888,922 options to purchase shares of our common stock to 34 employees. During the year ended December 31, 2015, we issued 80,000 options to purchase shares of our common stock to three 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, 2013 449,087 $ 10.85 Granted — — Exercised (46,526 ) 11.09 Cancelled/Forfeited — — Options outstanding December 31, 2014 402,561 $ 10.82 Granted 80,000 4.48 Exercised — — Cancelled/Forfeited (38,889 ) 11.23 Options Outstanding December 31, 2015 443,672 $ 9.64 Granted 888,922 1.66 Exercised — — Cancelled/Forfeited (151,494 ) 5.72 Options Outstanding December 31, 2016 1,181,100 $ 4.14 4.8 $ — Options Exercisable December 31, 2016 313,505 $ 10.31 1.2 $ — Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2016, and 2014 was $0.4 million and $0.1 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, 2016 and 2015. The intrinsic value of stock options exercised for the years ended December 31, 2014 was $0.3 million, respectively. The total tax benefit for the years ended December 31, 2016 and 2015 was negligible and for the year ended December 31, 2014 was approximately $0.1 million. 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, 2016 and 2015 are as follows: Year Ended December 31, 2016 2015 Expected dividend yield 0% 0% Expected stock price volatility 87.8% - 96.5% 56.4% - 59.5% Risk-free interest rate 1.1% - 1.5% 1.2% - 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, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 12/31/16 Weighted-Average Exercise Price Number Exercisable At 12/31/16 Weighted-Average Exercise Price $ 0.97 37,500 $ 0.97 — $ — $ 1.69 753,428 $ 1.69 — $ — $ 4.05 40,000 $ 4.05 — $ — $ 4.90 40,000 $ 4.90 3,333 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,181,100 $ 4.14 313,505 $ 10.31 The weighted average remaining contractual term for options exercisable at December 31, 2016 was 1.2 years and the aggregate intrinsic value was negligible. Restricted Stock Awards During the year ended December 31, 2016, the Compensation Committee issued 1,423,091 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. Certain of the restricted common stock awards in 2015 and 2014 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 and 2014 were $2.56 and $10.15 per share, respectively. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions: Year Ended December 31, 2015 Year Ended December 31, 2014 Expected Dividend Yield 0.0 % 0.0 % Risk-Free Interest Rate 1.0 % 0.8 % Expected Volatility – Rex Energy 58.6 % 50.4 % Expected Volatility – Peer Group 29.8%-85.0% 28.4%-65.7% Market Index 35.6 % 35.3 % Expected Life Three Years Three Years 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, 2016, 2015 and 2014 was $2.7 million, $5.8 million and $5.4 million, respectively. A summary of the restricted stock activity for the years ended December 31, 2016, 2015 and 2014 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of January 1, 2014 2,172,639 $ 14.16 Awards 131,610 8.76 Vested (595,085 ) 13.09 Forfeitures (189,863 ) 14.60 Restricted stock awards, as of December 31, 2014 1,519,301 $ 14.05 Awards 2,236,839 3.35 Vested (606,359 ) 9.39 Forfeitures (670,373 ) 11.33 Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 1,423,091 0.91 Vested (872,061 ) 7.33 Forfeitures (602,944 ) 6.73 Restricted stock awards, as of December 31, 2016 2,427,494 $ 2.63

Impairment Expense

Impairment Expense	12 Months Ended
	Dec. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment Expense	16. IMPAIRMENT EXPENSE For the years ended December 31, 2016, 2015 and 2014, we incurred impairment expense from continuing operations of approximately $74.6 million, $283.2 million and $20.2 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 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 proved 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. During 2014, we recorded impairment expense of $20.2 million. Approximately $9.8 million of the impairment incurred during 2014 was attributable to proved properties and other fixed assets in the Appalachian Basin, including approximately $5.9 million of impairment for our salt water disposal well in Ohio. This was due to the regulatory and environmental climate and the uncertainty of future viability of the disposal well. Approximately $3.6 million of the remaining proved property impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the estimated future decrease in natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $10.4 million in unproved property impairments related to expiring leases that will not be developed.

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2016
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 the years ended December 31, 2016, 2015 and 2014 ($ in thousands): 2016 2015 2014 Beginning Balance at January 1, $ 16,970 $ 22,573 $ 5,517 Additions to capitalized exploratory well costs pending the determination of estimated proved reserves 46,759 144,333 252,115 Divested wells — — — Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves (39,126 ) (147,054 ) (235,039 ) Capitalized exploratory well costs charged to expense (7,402 ) (2,882 ) (20 ) Ending Balance at December 31, 17,201 16,970 22,573 Less exploratory well costs that have been capitalized for a period of one year or less (17,201 ) (12,049 ) (19,879 ) Capitalized exploratory well costs for a period of greater than one year $ — $ 4,921 $ 2,694 Number of projects that have exploratory well costs capitalized for a period of more than one year — 13 6 As of December 31, 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, 2016
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): 2016 2015 2014 Consolidated Entities: Acquisition of Properties Proved $ — $ — $ 161 Unproved 6,671 27,933 165,655 Exploration Costs(a) 24,650 157,067 306,752 Development Costs(a) 11,166 17,336 35,996 Subtotal 42,487 202,336 508,564 Asset Retirement Obligations 1,927 2,739 1,792 Total Costs Incurred $ 44,414 $ 205,075 $ 510,356 Share of Equity Method Investments: Acquisition of Properties Proved $ — $ — $ — Unproved — — — Exploration Costs — — — Development Costs(a) 793 824 438 Total $ 793 $ 824 $ 438 (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): 2016 2015 2014 Total Costs Incurred by Consolidated Entities $ 44,414 $ 205,075 $ 510,356 Illinois Basin Expenditures — 15,405 55,941 Exploration Expense (2,178 ) (2,617 ) (9,446 ) Asset Retirement Obligations (1,927 ) (2,739 ) (1,792 ) Depreciation for Support Equipment and Facilities — (4,905 ) (6,075 ) Corporate Expenditures — 231 869 Other (a) — (16,522 ) 7,223 Total Capital Expenditures $ 40,309 $ 193,928 $ 557,076 (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, 2016
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): 2016 2015 Consolidated Entities: Proven Oil and Natural Gas Properties $ 1,055,467 $ 943,092 Pipelines and Support Equipment 21,088 16,135 Field Operation Vehicles and Other Equipment 11,239 10,667 Wells and Facilities in Progress 21,964 140,953 Unproven Properties 215,794 262,992 Total 1,325,552 1,373,839 Less Accumulated Depreciation and Depletion (474,046 ) (427,321 ) Total $ 851,506 $ 946,518 Share of Equity Method Investments: Pipelines and Support Equipment 19,962 19,970 Wells and Facilities in Progress — — Total 19,962 19,970 Less Accumulated Depreciation and Depletion (4,211 ) (3,411 ) Total $ 15,751 $ 16,559

Oil and Natural Gas Reserve Qua

Oil and Natural Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2016
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, 2016, 2015 and 2014. 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, analogy to similar properties and volumetric calculations. 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, 2016, 2015 and 2014. 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. 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 ) (46,809.3 ) Production (360.4 ) (4,107.4 ) (44,618.1 ) (71,424.9 ) Estimated Proved Reserves-End of Period 1,866.0 44,824.4 367,640.9 647,783.3 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 ) Sales of Reserves (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 2014 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 8,619.6 46,130.7 521,282.8 849,784.6 Extensions, Discoveries and Additions 1,723.1 31,160.3 326,464.2 523,764.6 Revisions of Previous Estimates 471.1 (2,889.1 ) 9,971.0 (4,537.0 ) Purchases 12.0 933.0 18,478.3 24,148.3 Production (1,141.1 ) (2,082.4 ) (37,011.2 ) (56,352.2 ) Estimated Proved Reserves-End of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Proved Developed Reserves 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 December 31, 2014 7,628.1 29,215.0 365,673.3 586,731.9 Proved Undeveloped Reserves December 31, 2016 — — — — December 31, 2015 372.5 2,404.7 16,708.4 33,371.6 December 31, 2014 2,056.6 44,037.5 473,511.8 750,076.4 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 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. Our revisions in 2014 included a negative adjustment of approximately 58.5 Bcfe related to PUD locations that were not developed within five years, negative revisions of 1.6 Bcfe related to commodity pricing, positive revisions of 17.6 Bcfe related to favorable operating expenses and positive technical revisions of 38.0 Bcfe. The negative revisions were related to PUD locations that were previously booked in our Butler County, Pennsylvania region. The positive technical revisions included 51.0 Bcfe in our Butler County, Pennsylvania area related to positive well performance which was partially offset by negative revisions related to well performance in our Warrior South prospect and our non-operated Westmoreland County, Pennsylvania area of approximately 15.5 Bcfe. 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, 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 Bcf of natural gas. During 2014, we had extensions, discoveries and other additions of 1.7 MMBOE of oil, 31.2 MMBOE of NGLs and 326.5 Bcf 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, 2016, 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, 2016
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 proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2016, 2015 and 2014 ($ in thousands): 2016 2015 2014 Future Cash Inflows $ 1,371,210 (a) $ 1,716,131 (b) $ 5,824,231 (c) Future Costs: Production (1,061,275 ) (1,144,049 ) (2,332,151 ) Abandonment (47,159 ) (143,459 ) (134,308 ) Development — (18,952 ) (686,676 ) Net Future Cash Inflow Before Income Taxes 262,776 409,671 2,671,096 Future Income Tax Expense — — (468,597 ) Total Future Net Cash Flows Before 10.0% Discount 262,776 409,671 2,202,499 Less: Effect of 10.0% Discount Factor (97,179 ) (154,048 ) (1,177,135 ) Standardized Measure of Discounted Future Net Cash Flows $ 165,597 $ 255,623 $ 1,025,364 (a) Calculated using weighted average prices of $2.264 per Mcf, $36.68 per barrel of oil and $10.50 per barrel of NGLs (b) Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs (c) Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs The principal sources of change in the standardized measure of discounted future net cash flows are as follows: 2016 2015 2014 Standardized Measure – Beginning of Period $ 255,623 $ 1,025,364 $ 529,113 Revisions of Previous Estimates: Changes in Prices and Production Costs (89,583 ) (1,296,866 ) 253,865 Revisions in Quantities 9,851 (270,673 ) (5,970 ) Changes in Future Development Costs 7,786 595,547 (51,794 ) Accretion of Discount and Timing of Future Cash Flows 25,562 116,514 64,013 Net Change in Income Tax — 139,776 28,756 Purchase (Sale) of Reserves in Place (54,598 ) (37,101 ) 28,316 Plus Extensions, Discoveries, and Other Additions 21,841 88,152 430,252 Development Costs Incurred 11,166 31,574 71,383 Sales of Product – Net of Production Costs (34,301 ) (52,952 ) (197,587 ) Changes in Timing and Other 12,250 (83,712 ) (124,983 ) Standardized Measure – End of Period $ 165,597 $ 255,623 $ 1,025,364

Results Of Operations For Oil A

Results Of Operations For Oil And Gas Producing Activities	12 Months Ended
	Dec. 31, 2016
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): 2016 2015 2014 Consolidated Entities (in thousands): Revenues Oil and Natural Gas Sales $ 139,017 $ 138,749 $ 225,629 Expenses Production and Lease Operating Expense 104,699 93,892 69,547 Impairment Expense 74,619 283,244 20,225 Exploration Expense 2,178 2,617 6,813 Depletion, Depreciation, Amortization and Accretion 62,874 85,844 65,817 Total Costs 244,370 465,597 162,402 Pre-Tax Operating Income (Loss) (105,353 ) (326,848 ) 63,227 Income Tax Expense (a) (1,317 ) (5,687 ) (30,602 ) Results of Operations for Oil and Gas Producing Activities $ (106,670 ) $ (332,535 ) $ 32,625 Share of Equity Method Investments (in thousands): Expenses Depletion, Depreciation, Amortization and Accretion $ 813 $ 812 $ 805 Total Costs 813 812 805 Pre-Tax Operating Loss (813 ) (812 ) (805 ) Income Tax (Expense) Benefit (a) (10 ) (14 ) 390 Results of Operations for Oil and Gas Producing Activities $ (823 ) $ (826 ) $ (415 ) Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities $ (107,493 ) $ (333,361 ) $ 32,210 ( a ) Computed using the effective rate for continuing operations for each period: -1.25% in 2016; -1.74% in 2015 and; 48.4% in 2014.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Litigation	23. LITIGATION Illinois Basin EPA Consent Decree In September 2006, the United States Department of Justice (“DOJ”), the EPA and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) through our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, we entered a consent decree to resolve the enforcement action. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. It also required us to implement a Directed Inspection and Maintenance Plan, and to annually reassess such plan. The consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree. In 2010 and again in 2014, we proposed and the EPA, DOJ and Illinois EPA approved revisions to the Directed Inspection and Maintenance Plan. There were no material changes to the Directed Inspection and Maintenance Plan in 2015 or through September 30, 2016, and we were compliant with all reporting requirements for those periods. In August 2016, we sold all of our assets in the Illinois Basin (see Note 4 Discontinued Operations/Assets Held for Sale 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 those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 2013, 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 Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated. In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case. In July 2015, the trial court denied plaintiffs’ motion for class certification. Plaintiffs served notice of their appeal of that decision in August 2015 and filed the appeal in September 2015. In June 2016, we and the plaintiffs each presented our arguments on the appeal before a three-judge panel of the Pennsylvania Superior Court. In January 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. We promptly filed an application with the Pennsylvania Superior Court for rehearing of the arguments en banc. In the event the Superior Court does not agree to rehear the case, we will evaluate our alternatives, including a potential application for allowance to appeal to the Pennsylvania Supreme Court. We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2016
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) 2016 March June September December Revenues $ 25,686 $ 31,265 $ 34,039 $ 48,027 Impairment Expense 10,641 25,139 9,563 29,276 Other Costs and Expenses 67,696 59,037 40,953 94,349 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 $ (0.98 ) $ 0.24 $ (0.19 ) $ (0.78 ) Basic — Discontinued Operations (0.13 ) (0.02 ) 0.24 0.08 Basic — Net Income (Loss) $ (1.11 ) $ 0.22 $ 0.05 $ (0.69 ) Basic — Weighted Average Shares Outstanding 56,003 71,804 90,803 97,398 Diluted — Continuing Operations $ (0.98 ) $ 0.24 $ (0.19 ) $ (0.78 ) Diluted — Discontinued Operations (0.13 ) (0.02 ) 0.24 0.08 Diluted — Net Income (Loss) $ (1.11 ) $ 0.22 $ 0.05 $ (0.69 ) Diluted — Weighted Average Shares Outstanding 56,003 71,804 90,803 97,398 2015 March June September December Revenues $ 45,934 $ 35,784 $ 29,656 $ 27,375 Impairment Expense 6,848 117,839 85,193 73,364 Other Costs and Expenses 54,079 69,287 33,354 51,567 Net Loss From Continuing Operations (14,993 ) (151,342 ) (88,891 ) (97,556 ) Net Loss From Discontinued Operations, Net of Income Taxes (1,524 ) (461 ) (5,785 ) (481 ) Net Loss (16,517 ) (151,803 ) (94,676 ) (98,037 ) Net Income (Loss) Attributable to Noncontrolling Interests 1,297 949 (1 ) — Net Loss Attributable to Rex Energy (17,814 ) (152,752 ) (94,675 ) (98,037 ) Preferred Stock Dividends (2,415 ) (2,415 ) (2,415 ) (2,415 ) Net Loss Attributable to Common Shareholders $ (20,229 ) $ (155,167 ) $ (97,090 ) $ (100,452 ) Loss per Common Share Attributable to Rex Energy Common Shareholders: Basic — Continuing Operations $ (0.32 ) $ (2.84 ) $ (1.69 ) $ (1.84 ) Basic — Discontinued Operations (0.05 ) (0.03 ) (0.11 ) (0.01 ) Basic — Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Basic — Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342 Diluted — Continuing Operations $ (0.32 ) $ (2.84 ) $ (1.69 ) $ (1.84 ) Diluted — Discontinued Operations (0.05 ) (0.03 ) (0.11 ) (0 ) Diluted — Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Diluted — Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	25. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of December 31, 2016, we had $601.2 million of outstanding Senior Notes, as shown in Note 9, Long-Term Debt • Rex Energy I, LLC • Rex Energy Operating Corporation • Rex Energy IV, LLC • PennTex Resources Illinois, Inc. • R.E. Gas Development, LLC The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of December 31, 2016, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of December 31, 2016 and 2015, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2016. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2016 ($ 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 650 — 1,223 — 1,873 Inventory, Prepaid Expenses and Other 2,521 — 25 — 2,546 Total Current Assets 29,474 — 4,301 — 33,775 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,053,461 — — — 1,053,461 Unevaluated Oil and Gas Properties 215,794 — — — 215,794 Other Property and Equipment 21,401 — — — 21,401 Wells and Facilities in Progress 21,964 — — — 21,964 Pipelines 18,029 — — — 18,029 Total Property and Equipment 1,330,649 — — — 1,330,649 Less: Accumulated Depreciation, Depletion and Amortization (475,205 ) — — — (475,205 ) Net Property and Equipment 855,444 — — — 855,444 Other Assets 2,492 — — — 2,492 Intercompany Receivables — — 1,035,713 (1,035,713 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 500 — 1,712 — 2,212 Total Assets $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 40,712 — — — $ 40,712 Current Maturities of Long-Term Debt 764 — — — 764 Accrued Liabilities 32,328 421 4,458 — 37,207 Short-Term Derivative Instruments 25,025 — — — 25,025 Total Current Liabilities 98,829 421 4,458 — 103,708 Long-Term Derivative Instruments 7,227 — — — 7,227 Senior Secured Line of Credit, Net of Issuance Costs — — 113,785 — 113,785 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges — — 641,762 — 641,762 Discount on Senior Notes – Net — — (3,601 ) — (3,601 ) 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 — — 95 — 95 Additional Paid-In Capital 177,144 — 650,584 (177,144 ) 650,584 Accumulated Earnings (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 INCOME (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 0 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) Benefit (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 INCOME (LOSS) (146,290 ) (54 ) (176,715 ) 146,344 (176,715 ) Preferred Stock Dividends — — (5,091 ) — (5,091 ) Effect of Preferred Stock Conversions — — 72,984 — 72,984 NET INCOME (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 Income (Loss) $ (146,290 ) $ (54 ) $ (176,715 ) $ 146,344 $ (176,715 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (212 ) 3 24,333 — 24,124 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 Dry Hole Expense 905 — — — 905 Gain on Extinguishment of Debt — — (24,627 ) — (24,627 ) (Gain) Loss on Sale of Assets (34,697 ) 46 — — (34,651 ) Impairment Expense 78,160 2 78,162 (78,162 ) 78,162 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 (1,950 ) — — — (1,950 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES (3,946 ) (806 ) (67,834 ) 68,182 (4,404 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 3,628 (94 ) 64,648 (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 (USED IN) INVESTING ACTIVITIES 7,379 806 64,648 (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 ) Dividends Paid on Preferred Stock — NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (828 ) — 3,187 — 2,359 NET (DECREASE) 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 BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ 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 $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 17,225 — 49 — 17,274 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Assets Held for Sale 52,111 1,040 — — 53,151 Inventory, Prepaid Expenses and Other 3,034 — 25 — 3,059 Total Current Assets 107,719 1,040 94 — 108,853 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 950,062 — — (6,970 ) 943,092 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 20,363 — — — 20,363 Wells and Facilities in Progress 141,370 — — (270 ) 141,100 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,390,948 — — (9,377 ) 1,381,571 Less: Accumulated Depreciation, Depletion and Amortization (434,046 ) — — 3,518 (430,528 ) Net Property and Equipment 956,902 — — (5,859 ) 951,043 Deferred Financing Costs and Other Assets—Net 2,501 — — — 2,501 Intercompany Receivables — — 1,070,548 (1,070,548 ) — Investment in Subsidiaries – Net (1,907 ) — 243,331 (241,424 ) — Long-Term Derivative Instruments 9,534 — — — 9,534 Total Assets $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 36,785 $ — $ — $ — $ 36,785 Current Maturities of Long-Term Debt 402 — — — 402 Accrued Liabilities 28,883 — 11,725 — 40,608 Short-Term Derivative Instruments 2,486 — — — 2,486 Liabilities Related to Assets Held For Sale 36,289 31 — — 36,320 Total Current Liabilities 104,845 31 11,725 — 116,601 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 18 — 109,368 — 109,386 Senior Notes, Net of Issuance Costs — — 663,089 — 663,089 Premium on Senior Notes – Net — — 2,344 — 2,344 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 11,159 409 — — 11,568 Intercompany Payables 1,070,095 453 — (1,070,548 ) — Total Liabilities 1,194,829 893 786,526 (1,070,548 ) 911,700 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,143 — 619,777 (173,057 ) 623,863 Accumulated Earnings (Deficit) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 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 INCOME (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 0 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 Benefit (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 Tax (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 by Operating Activities Loss on Equity Method Investments 411 — — — 411 Non-Cash Expenses (Income) (201 ) (334 ) 8,184 — 7,649 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 Dry Hole Expense 199 136 — (5 ) 330 Gain on Sale of Assets (477 ) (44 ) — — (521 ) Gain on Sale of Water Solutions — — (57,778 ) — (57,778 ) Impairment Expense 345,892 1,396 345,892 (347,405 ) 345,775 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 BY (USED IN) OPERATING ACTIVITIES 103,325 36,717 (67,034 ) (42,123 ) 30,885 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 96,763 (37,424 ) (100,298 ) 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 BY (USED IN) INVESTING ACTIVITIES (119,215 ) (44,956 ) (33,398 ) 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 ) Distributions by the Partners of Consolidated Subsidiary — (830 ) — — (830 ) Dividends Paid on Preferred Stock — — (9,660 ) — (9,660 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (999 ) 8,126 100,429 — 107,556 NET (DECREASE) IN CASH (16,889 ) (113 ) (3 ) 0 (17,005 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH - ENDING $ 1,089 $ 0 $ 2 $ 0 $ 1,091 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 225,511 $ — $ — $ — $ 225,511 Other Revenue 118 — — — 118 TOTAL OPERATING REVENUE 225,629 — — — 225,629 OPERATING EXPENSES Production and Lease Operating Expense 69,547 — — — 69,547 General and Administrative Expense 26,105 75 5,737 — 31,917 Loss on Disposal of Assets 218 — — — 218 Impairment Expense 14,269 5,956 — — 20,225 Exploration Expense 6,813 — — — 6,813 Depreciation, Depletion, Amortization and Accretion 65,816 1 — — 65,817 Other Operating Expense 312 — — — 312 TOTAL OPERATING EXPENSES 183,080 6,032 5,737 — 194,849 INCOME (LOSS) FROM OPERATIONS 42,549 (6,032 ) (5,737 ) — 30,780 OTHER INCOME (EXPENSE) Interest Expense (110 ) — (36,835 ) — (36,945 ) Gain on Derivatives, Net 37,359 — 1,517 — 38,876 Other Income (Expense) 73 — — — 73 Loss From Equity Method Investments (813 ) — — — (813 ) Income (Loss) From Equity in Consolidated Subsidiaries (3,131 ) 3,131 (25,250 ) 25,250 — TOTAL OTHER INCOME (EXPENSE) 33,378 3,131 (60,568 ) 25,250 1,191 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX 75,927 (2,901 ) (66,305 ) 25,250 31,971 Income Tax (Expense) Benefit (38,230 ) 2,917 19,853 — (15,460 ) NET INCOME (LOSS) FROM CONTINUING OPERATIONS 37,697 16 (46,452 ) 25,250 16,511 Income (Loss) From Discontinued Operations, Net of Income Taxes (63,582 ) 4,658 (237 ) — (59,161 ) NET INCOME (LOSS) (25,885 ) 4,674 (46,689 ) 25,250 (42,650 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 4,039 — — 4,039 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (25,885 ) $ 635 $ (46,689 ) $ 25,250 $ (46,689 ) Preferred Stock Dividends — — (2,335 ) — (2,335 ) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (25,885 ) $ 635 $ (49,024 ) $ 25,250 $ (49,024 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (25,885 ) $ 4,674 $ (46,689 ) $ 25,250 $ (42,650 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 813 — — — 813 Non-Cash Expenses (Income) (273 ) 278 6,784 — 6,789 Depreciation, Depletion, Amortization and Accretion 94,643 4,217 — (689 ) 98,171 Deferred Income Tax Benefit (9,928 ) (1,649 ) (14,415 ) — (25,992 ) Gain on Derivatives (37,359 ) — (1,517 ) — (38,876 ) Cash Settlements of Derivatives 5,969 — 1,312 — 7,281 Dry Hole Expense 3,797 267 — — 4,064 (Gain) Loss on Sale of Assets 644 (55 ) — — 589 Impairment Expense 126,662 6,022 — — 132,684 Changes in operating assets and liabilities Accounts Receivable (11,450 ) (6,090 ) 4,686 (766 ) (13,620 ) Inventory, Prepaid Expenses and Other Assets (1,283 ) (74 ) (2 ) — (1,359 ) Accounts Payable and Accrued Liabilities 23,768 3,488 9,252 766 37,274 Other Assets and Liabilities (2,127 ) (335 ) — — (2,462 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 167,992 10,743 (40,589 ) 24,561 162,706 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 401,412 (756 ) (371,768 ) (28,888 ) — Proceeds from Joint Venture Acreage Management 263 — — — 263 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 254 292 — — 546 Acquisitions of Undeveloped Acreage (168,713 ) (710 ) — — (169,423 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (382,889 ) (12,861 ) — 4,328 (391,422 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (149,673 ) (14,035 ) (371,768 ) (24,560 ) (560,036 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 38,895 171,000 — 209,895 Repayments of Long-Term Debt and Lines of Credit — (33,152 ) (230,000 ) — (263,152 ) Repayments of Loans and Other Notes Payable (1,727 ) (994 ) — — (2,721 ) Proceeds from Senior Notes, net of Discounts and Premiums — — 325,000 — 325,000 Debt Issuance Costs — (8 ) (6,816 ) — (6,824 ) Proceeds from Issuance of Preferred Stock, Net — — 154,988 — 154,988 Proceeds from the Exercise of Stock Options — — 515 — 515 Purchase of Non-Controlling Interests — (1,840 ) — — (1,840 ) Dividends Paid on Preferred Stock — — (2,335 ) — (2,335 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (1,727 ) 2,901 412,352 — 413,526 NET INCREASE (DECREASE) IN CASH 16,592 (391 ) (5 ) — 16,196 CASH – BEGINNING 1,386 504 10 — 1,900 CASH - ENDING $ 17,978 $ 113 $ 5 $ — $ 18,096

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	26. SUBSEQUENT EVENTS Sale of Warrior South Assets On January 11, 2017, we, together with MFC Drilling, Inc. (“MFC”), ABARTA Oil & Gas Co., Inc. (“ABARTA”) (Rex, MFC, and ABARTA, together, the “Sellers”) sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation (“Antero”). These interests comprised Rex’s Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to Rex, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017. Approximately $5.0 million of the total proceeds due to us will be held in escrow and will be released in January 2018, net of post-closing adjustments. Net book value of the assets at December 31, 2016 was approximately $27.9 million. The sale assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to Rex, and approximately 6,200 gross acres, with 4,100 acres net to Rex. This acreage was considered non-core to Rex. We used the proceeds from the transaction to pay down our revolving line of credit and for general corporate purposes. Amendment to Senior Credit Agreement Effective as of January 11, 2017, the company entered into a Twelfth Amendment (the “Twelfth Amendment”) to the Amended and Restated Credit Agreement dated as of March 27, 2013 (as amended, modified or supplemented, the “Credit Agreement”) among the company; each of the guarantors; Royal Bank of Canada, as administrative agent for the lenders; and the other lenders signatory thereto. The Twelfth Amendment amended certain provisions of the Credit Agreement to, among other things, (i) provide that there was to be no adjustment to the borrowing base upon the completion of the sale of assets in the Warrior South Area, with the effect that the borrowing base remained at $190,000,000 pending the next redetermination; and (ii) reduce the commitment level for letters of credit within the Credit Agreement to the greater of (a) forty million dollars ($40,000,000) and (b) (x) fifty million dollars ($50,000,000) minus (y) an amount equal to the portion of the face amount of all Surety LCs (as defined in the Credit Agreement) reduced or terminated on or after the Twelfth Amendment Effective Date in excess of $10,000,000 in the aggregate.

Summary Of Significant Accoun34

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 oil, NGL and natural gas 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, 2016 and 2015, our Cash and Cash Equivalents consisted of only cash.
Accounts Receivable	Accounts Receivable Our trade accounts receivable, which are primarily from condensate, NGLs and natural gas 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, 2016 and 2015 were $0.1 million and $0.2 million, respectively. To the extent actual quantities and values of condensate, NGLs and natural gas 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, 2016, we carried approximately $22.2 million in production receivable, of which approximately $17.5 million were production receivables due from our three largest purchasers.
Inventory	Inventory Inventory is valued at the lower of cost or market value and consists of our ownership interest in condensate and NGLs held in terminal tanks located in the field. Condensate and NGL 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.
Oil, NGL and Natural Gas Property, Depreciation and Depletion	Oil, NGL and Natural Gas Property, Depreciation and Depletion We account for oil, NGL and natural gas 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 proved 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, 2016, 2015 and 2014, we capitalized interest costs of $2.7 million, $7.7 million and $7.3 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 oil and natural gas 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 oil, NGL and natural gas 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 oil and gas 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 oil, NGL and natural gas 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 $74.6 million, $283.2 million and $20.2 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2016, 2015 and 2014, 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, 2016 and 2015, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated 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 condensate, NGL and natural gas 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 engineer estimates 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, 2016, 2015 and 2014 totaled approximately $1.0 million, $1.0 million and $0.7 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2016 and 2015, approximately $1.1 million December 31, 2016 (in thousands) December 31, 2015 (in thousands) Beginning Balance $ 11,934 $ 8,061 Asset Retirement Obligation Incurred 575 1,063 Asset Retirement Obligation Settled (671 ) (449 ) Asset Retirement Obligation Cancelled or Sold Properties (4,876 ) (136 ) Asset Retirement Obligation Revision of Estimated Obligation 1,918 2,428 Asset Retirement Obligation Accretion Expense 985 967 Total Future Abandonment Costs $ 9,865 $ 11,934
Revenue Recognition	Revenue Recognition Condensate, NGL and natural gas revenue is recognized when the condensate, NGL or natural gas 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 and NGL sales, title is transferred to the purchaser when the condensate or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of condensate, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for condensate, NGLs and natural gas 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. The point of sale for our condensate, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for condensate and NGL production held in stock tanks before delivery to the purchaser. To the extent actual quantities and values of condensate, NGLs and natural gas 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 Natural Gas, NGL and Condensate Sales on the Statements of Operations. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
Derivative Instruments	Derivative Instruments We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of condensate, natural gas and NGLs. 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 2016, 2015 and 2014 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 oil, natural gas and NGL 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 . Employee Benefit and Equity Plans, In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting We elected to early adopt ASU 2016-09 effective January 1, 2016.
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, 2016, we had 97,870,608 common shares outstanding, 1,181,100 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 2,427,494 restricted stock awards, of which approximately 617,479 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs We adopted this ASU on January 1, 2016. In conjunction with the adoption of ASU 2015-03, we reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and $ Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. Adoption did not have an impact on Net Income or Accumulated Deficit. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. An entity should apply the amendments in this ASU using one of the following two methods: 1) Retrospectively to each prior reporting period presented. 2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes 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 March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting We elected to early adopt ASU 2016-09 effective January 1, 2016 utilizing a modified retrospective approach. An income tax benefit of approximately $1.3 million representing previously unrecognized tax benefits originating from our deferred compensation plans was recognized as of January 1, 2016 through a cumulative adjustment to retained earnings. As the deferred tax asset generated by the cumulative effect adjustment was subject to a full valuation allowance, there is no cumulative effect to retained earnings as a result of the adoption of ASU 2016-09. With the adoption of ASU 2016-09 we are electing to continue our current process of estimating the number of forfeitures of equity based awards in accounting for our deferred compensation plans. As such, this election has no cumulative effect on retained earnings. We have elected to present the cash flow statement on a prospective transition method and no prior periods have been adjusted. As required by ASU 2016-09, we have adjusted our earnings per share calculation model to exclude the tax effect of any anticipated windfall benefits or shortfalls, when projecting proceeds available for share repurchases. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments . The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues: • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

Summary Of Significant Accoun35

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 (in thousands) December 31, 2015 (in thousands) Beginning Balance $ 11,934 $ 8,061 Asset Retirement Obligation Incurred 575 1,063 Asset Retirement Obligation Settled (671 ) (449 ) Asset Retirement Obligation Cancelled or Sold Properties (4,876 ) (136 ) Asset Retirement Obligation Revision of Estimated Obligation 1,918 2,428 Asset Retirement Obligation Accretion Expense 985 967 Total Future Abandonment Costs $ 9,865 $ 11,934

Business and Oil and Gas Prop36

Business and Oil and Gas Property Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2016
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. No proceeds were received for the quarter ending December 31, 2016, as WTI prices did not meet the necessary threshold. For additional information, see Note 10, Fair Value of Financial Instruments and Derivative Instruments Calendar Quarter Ending West Texas Intermediate Average Price per Bbl 3/31/2017 $ 56.25 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (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_Asset37

Discontinued Operations/Assets Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2016
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	The carrying value of assets and liabilities of our Illinois Basin operations that are classified as Held for Sale in the accompanying Consolidated Balance Sheets at December 31, 2015 are as follows: December 31, ($ in Thousands) 2015 Assets: Accounts Receivable $ 2,209 Inventory, Prepaid Expenses and Other 770 Total Current Assets 2,979 Evaluated Oil & Gas Properties 296,338 Other Property and Equipment, Net 19,749 Wells and Facilities in Progress 3,456 Accumulated Depreciation, Depletion, and Amortization (269,371 ) Total Long-Term Assets 50,172 Total Assets Held for Sale $ 53,151 Liabilities: Accounts Payable 1,089 Current Maturities of Long-Term Debt 188 Accrued Liabilities 3,718 Total Current Liabilities 4,995 Long-Term Debt 10 Future Abandonment Cost 31,315 Total Long-Term Liabilities 31,325 Total Liabilities Related to Assets Held for Sale $ 36,320 Net Assets Held for Sale: $ 16,831
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) 2016 2015 2014 Revenues: Field Services Revenue $ — $ 33,086 $ 58,627 Total Operating Revenue — 33,086 58,627 Costs and Expenses: General and Administrative Expense — 1,961 4,081 Depreciation, Depletion, Amortization and Accretion — 78 3,703 Impairment Expense — — 67 Field Service Operating Expense — 25,981 44,369 Gain on Disposal of Asset — (44 ) (55 ) Interest Expense — 487 628 Other (Income) Expense — (57,589 ) 66 Total Costs and Expenses (Income) — (29,126 ) 52,859 Income from Discontinued Operations Before Income Taxes — 62,212 5,768 Income Tax Expense — (24,227 ) (768 ) Income from Discontinued Operations, net of taxes — $ 37,985 $ 5,000
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, 2016, 2015, and 2014. December 31, ($ in Thousands) 2016 2015 2014 Revenues: Oil Sales $ 11,282 $ 33,244 $ 72,359 Total Operating Revenue 11,282 33,244 72,359 Costs and Expenses: Production and Lease Operating Expense 11,033 25,099 30,556 General and Administrative Expense 1,002 2,741 4,219 (Gain) Loss on Disposal of Assets (30,530 ) 63 426 Impairment Expense 3,543 62,531 112,394 Exploration Expense 143 394 2,633 Depreciation, Depletion, Amortization and Accretion 5,100 18,900 28,650 Interest Expense 4 23 32 Other (Income) Expense 65 (14 ) (16 ) Total Costs and Expenses (9,640 ) 109,737 178,894 Income (Loss) from Discontinued Operations Before Income Taxes 20,922 (76,493 ) (106,535 ) Income Tax Benefit — 30,257 42,374 Income (Loss) from Discontinued Operations, net of taxes $ 20,922 $ (46,236 ) $ (64,161 ) Production: Crude Oil (Bbls) 310,388 729,251 806,162

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	At December 31, 2016 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.9 million, $1.0 million and $0.8 million for the years ended December 31, 2016, 2015 and 2014, respectively. Lease commitments by year for each of the next five years are presented in the table below. ($ in Thousands) 2017 $ 997 2018 565 2019 563 2020 422 2021 — Thereafter — Total $ 2,547
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 2017 $ 43,260 2018 46,685 2019 47,721 2020 46,413 2021 43,459 Thereafter 481,821 Total $ 709,359
Fee for Unconventional Gas Wells	The fee for each unconventional natural gas well is determined using the following matrix with vertical unconventional natural gas wells being charged 20%: <$2.25(a) $2.26 - $2.99(a) $3.00 - $4.99(a) $5.00 - $5.99(a) >$5.99(a) Year One $ 40,200 $ 45,300 $ 50,300 $ 55,300 $ 60,400 Year Two $ 30,200 $ 35,200 $ 40,200 $ 45,300 $ 55,300 Year Three $ 25,200 $ 30,200 $ 30,200 $ 40,200 $ 50,300 Year 4 – 10 $ 10,100 $ 15,100 $ 20,100 $ 20,100 $ 20,100 Year 11 – 15 $ 5,000 $ 5,000 $ 10,100 $ 10,100 $ 10,100 (a) Pricing utilized for determining annual fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the year ending December 31.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Components of Long-Term Debt and Lines of Credit	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at December 31, 2016 and December 31, 2015: ($ in Thousands) December 31, 2016 December 31, 2015 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges(b) $ 641,762 $ 663,089 Premium (Discount) on Senior Notes, Net (3,601 ) 2,344 Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs (a)(c) 113,785 109,386 Capital Leases and Other Obligations (a) 4,173 419 Total Debt 756,119 775,238 Less Current Portion of Long-Term Debt (764 ) (402 ) Total Long-Term Debt $ 755,355 $ 774,836 (a) The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2016, 2015 and 2014 was approximately 3.8%, 1.7 % and 2.2%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2016, 2015 and 2014 was approximately 12.6%, 5.5% and 4.0%, respectively (b) Includes unamortized debt issuance and financing costs of approximately ($7.9) million and $11.9 million as of December 31, 2016 and 2015, respectively. (c) Includes unamortized debt issuance costs of approximately $3.9 million and $2.1 million as of December 31, 2016 and 2015, respectively. .
Principal Maturity Schedule for Total Debt Outstanding	The following is the principal maturity schedule for total debt outstanding as of December 31, 2016: ($ in thousands) 2017 $ 764 2018 807 2019 118,614 2020 596,633 2021 554 Thereafter 5,649 Total 1 $ 723,021 1 Does not include $3.6 million net discount on Senior Notes, $32.7 million of unamortized deferred gain on debt exchanges or ($4.0) million of amortization of deferred financing costs.

Fair Value Of Financial Instr40

Fair Value Of Financial Instruments And Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	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, 2016, 2015 and 2014: For the Year Ended December 31, ($ in Thousands) 2016 2015 2014 Oil $ (1,515 ) $ 7,132 $ 8,613 Natural Gas (15,036 ) 37,647 18,406 NGLs (17,788 ) 14,839 10,340 Interest Rate — 934 1,517 Refined Products 54 (376 ) — Contingent Consideration 1,770 — — Gain (Loss) on Derivatives, Net $ (32,515 ) $ 60,176 $ 38,876
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2016 consisted of the following: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2017 - Deferred Premium Put 15,000 Bbls $ — $ 51.00 $ — $ — $ (9 ) 2017 - Swaps 81,000 Bbls — — — 53.30 (220 ) 2017 - Collars 48,000 Bbls — 45.00 57.20 — (86 ) 2017 - Three-Way Collars 93,000 Bbls 40.16 49.68 61.50 — (132 ) 2018 - Swaps 60,000 Bbls — — — 54.00 (146 ) 2018 - Three-Way Collars 60,000 Bbls 43.00 52.00 62.30 — (58 ) 357,000 Bbls $ (651 ) Natural Gas 2017 - Swaps 11,000,000 Mcf $ — $ — $ — $ 3.11 $ (4,468 ) 2017 - Swaptions — Mcf — — — 3.15 (1,258 ) 2017 - Cap Swaps 3,900,000 Mcf 2.35 — — 2.81 (3,303 ) 2017 - Three-Way Collars 17,510,000 Mcf 2.33 3.01 3.87 — (2,246 ) 2017 - Calls 3,000,000 Mcf — — 3.64 — (1,478 ) 2017 - Basis Swaps - Dominion South 14,745,000 Mcf — — — (0.86 ) (53 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (355 ) 2017 - Collars 1,700,000 Mcf — 2.54 3.20 — (873 ) 2018 - Swaps 5,510,000 Mcf — — — 3.25 (797 ) 2018 - Swaptions — Mcf — — — 3.15 (167 ) 2018 - Collars 450,000 Mcf — 3.20 3.65 — (115 ) 2018 - Three-Way Collars 8,775,000 Mcf 2.30 2.89 3.58 — (1,786 ) 2018 - Basis Swaps - Dominion South 16,242,500 Mcf — — — (0.82 ) (193 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (355 ) 2018 - Calls 5,810,000 Mcf — — 3.97 — (491 ) 2019 - Basis Swaps - Dominion South 16,242,500 Mcf — — — (0.81 ) (230 ) 2020 - Basis Swaps - Dominion South 13,542,000 Mcf — — — (0.80 ) (189 ) 147,627,000 Mcf $ (18,357 ) NGLs 2017 C3 + NGL Swaps 1,337,000 Bbls $ — $ — $ — $ 28.14 $ (8,197 ) 2017 Ethane Swaps 840,000 Bbls — — — 10.50 (1,698 ) 2018 C3 + NGL Swaps 852,000 Bbls — — — 28.98 (2,082 ) 2018 Ethane Swaps 300,000 Bbls — — — 13.02 (118 ) 3,329,000 Bbls $ (12,095 )
Combined Fair Value of Derivatives	The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015 is summarized below. December 31, December 31, ($ in Thousands) 2016 2015 Short-Term Derivative Assets: Crude Oil—Collars $ — $ 1,078 Crude Oil—Deferred Put Spread — 852 Crude Oil—Three-Way Collars — 577 NGL—Swaps — 10,250 Natural Gas—Swaps 206 9,010 Natural Gas—Cap Swaps 61 1,977 Natural Gas—Basis Swaps 232 70 Natural Gas—Three-Way Collars 151 6,183 Natural Gas—Collars — 1,728 Natural Gas—Swaption — 798 Natural Gas—Put Spread — 1,737 Contingent Consideration - Sale of Illinois Basin 1,223 — Total Short-Term Derivative Assets $ 1,873 $ 34,260 Long-Term Derivative Assets: NGL—Swaps $ — $ 344 Natural Gas—Cap Swaps — 2,294 Natural Gas—Swaps 206 1,593 Natural Gas—Basis Swaps 293 195 Natural Gas—Three-Way Collars — 5,108 Contingent Consideration - Sale of Illinois Basin 1,713 — Total Long-Term Derivative Assets $ 2,212 $ 9,534 Total Derivative Assets $ 4,085 $ 43,794 Short-Term Derivative Liabilities: Refined Product —Swaps — (376 ) Crude Oil—Collars (86 ) — Crude Oil—Deferred Premium Put (9 ) — Crude Oil—Three-Way Collars (132 ) — Crude Oil—Swaps (220 ) — NGL—Swaps (9,895 ) — Natural Gas—Three-Way Collars (2,397 ) (31 ) Natural Gas—Cap Swaps (3,364 ) — Natural Gas—Collars (873 ) — Natural Gas—Basis Swaps (640 ) (1,585 ) Natural Gas—Call (1,478 ) — Natural Gas—Swaption (1,258 ) (202 ) Natural Gas—Swaps (4,673 ) (292 ) Total Short - Term Derivative Liabilities $ (25,025 ) $ (2,486 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars (58 ) — Crude Oil—Swaps (146 ) — NGL—Swaps (2,200 ) — Natural Gas—Swaps (1,004 ) — Natural Gas—Collars (115 ) — Natural Gas—Swaption (167 ) (297 ) Natural Gas—Basis Swaps (1,260 ) (4,186 ) Natural Gas—Call (491 ) (989 ) Natural Gas—Three-Way Collars (1,786 ) (84 ) Total Long-Term Derivative Liabilities $ (7,227 ) $ (5,556 ) Total Derivative Liabilities $ (32,252 ) $ (8,042 )
Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps	The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of December 31, 2015 are included in the table below. As of December 31, 2015 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.27) - ($1.08) $ (0.74 ) $ (5,468 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.05) - ($0.17) $ (0.12 ) $ (38 )
Fair Value 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, 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 ) $ — Fair Value Measurements at December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 )
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, 2016 and 2015 (in thousands): For the Year Ended December 31, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value 7,249 (2,548 ) Transfers out of Level 3 (1,564 ) — Purchases — — Settlements Received (179 ) (4,299 ) Ending Balance of Level 3 $ — $ (5,506 )
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, 2016 December 31, 2015 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 641,762 $ 147,605 $ 663,089 $ 137,402 Secured Lines of Credit 113,785 113,785 109,396 109,396 Capital Leases and Other Obligations 4,173 3,234 419 411 Total $ 759,720 $ 264,624 $ 772,904 $ 247,209

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Current: Federal $ 1,839 $ — $ — State 597 — 10 Deferred: Federal — 5,773 13,094 State — 257 2,356 Income Tax Expense $ 2,436 $ 6,030 $ 15,460
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, 2016 Year Ended December 31, 2015 Year Ended December 31, 2014 Income (Loss) from continuing operations before noncontrolling interests and income taxes $ (195,201 ) $ (346,752 ) $ 31,971 Statutory U.S. income tax rate 35.0 % 35.0 % 35.0 % Tax expense recognized using statutory U.S. income tax rate $ (68,320 ) $ (121,363 ) $ 11,190 State income taxes, net of federal income tax benefit (3,632 ) (17,137 ) 1,626 Change in estimated future state rates (400 ) (212 ) (743 ) Permanent differences 2,264 1,784 1,014 Change in valuation allowances 72,784 143,566 2,450 Other (260 ) (608 ) (77 ) Total income tax expense $ 2,436 $ 6,030 $ 15,460 Effective income tax rate -1.25 % -1.74 % 48.4 %
Components of Deferred Tax Assets (Liabilities)	Deferred tax assets (liabilities) are comprised of the following at December 31, 2016 and 2015: For the Years Ended December 31, ($ in Thousands) 2016 2015 (a) Tax effects of temporary differences for: Assets: Asset retirement obligation $ 3,955 $ 17,831 Deferred compensation plans 1,581 3,111 Compensation Accruals 762 767 Unrealized loss on derivatives 11,760 — Tax basis of oil and gas properties in excess of book basis — 8,965 Net operating loss carryforwards 79,531 123,488 Deferred Financing Costs (b) 182,519 — Gas Transportation Capacity Commitments 3,031 — Deferred revenue timing differences 443 969 Organization costs 391 456 Percentage depletion carryforward 2,717 2,673 AMT credits 2,131 292 Timing differences - tax partnerships 1,046 4,166 Other 331 372 Valuation allowances (212,041 ) (148,159 ) (c) Total Deferred Tax Assets net of Valuation Allowances $ 78,157 $ 14,931 Liabilities: Book basis of oil and gas properties in excess of tax basis (77,690 ) — Unrealized gain on derivatives — (14,144 ) Other (467 ) (787 ) Total Deferred Tax Liabilities $ (78,157 ) $ (14,931 ) (a) As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities for the year ended December 31, 2015 does not include $1.3 million of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. (b) Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016. (c) Includes approximately $11.3 million of valuation allowances recorded to offset deferred tax assets attributes of our discontinued operations.
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 1 2024 — 2025 — 2026 455 2027 968 2028 — 2029 — 2030 — 2031 1,522 2032 — 2033 12,653 2034 6,241 2035 45,296 2036 12,395 Total 79,531

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) 2016 2015 2014 Numerator: Net Income (Loss) From Continuing Operations $ (197,637 ) $ (352,782 ) $ 16,511 Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests 20,922 (10,496 ) (63,200 ) Less: Preferred Stock Dividends (5,091 ) (9,660 ) (2,335 ) Effect of Preferred Stock Conversions 72,984 — — Net Loss Attributable to Common Shareholders $ (108,822 ) $ (372,938 ) $ (49,024 ) Denominator: Weighted Average Common Shares Outstanding - Basic 79,256 54,392 53,150 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 79,256 54,392 53,150 Earnings per Common Share Attributable to Rex Energy Common Shareholders(a): Basic — Net Income (Loss) From Continuing Operations $ (1.63 ) $ (6.66 ) $ 0.27 — Net Income (Loss) From Discontinued Operations 0.26 (0.19 ) (1.19 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (1.37 ) $ (6.85 ) $ (0.92 ) Diluted — Net Income (Loss) From Continuing Operations $ (1.63 ) $ (6.66 ) $ 0.27 — Net Income (Loss) From Discontinued Operations 0.26 (0.19 ) (1.19 ) — Net Loss Attributable to Rex Energy Common Shareholders $ (1.37 ) $ (6.85 ) $ (0.92 ) (a) All earnings per share amounts are attributable to Rex common shareholders.

Employee Benefit And Equity P43

Employee Benefit And Equity Plans (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2013 449,087 $ 10.85 Granted — — Exercised (46,526 ) 11.09 Cancelled/Forfeited — — Options outstanding December 31, 2014 402,561 $ 10.82 Granted 80,000 4.48 Exercised — — Cancelled/Forfeited (38,889 ) 11.23 Options Outstanding December 31, 2015 443,672 $ 9.64 Granted 888,922 1.66 Exercised — — Cancelled/Forfeited (151,494 ) 5.72 Options Outstanding December 31, 2016 1,181,100 $ 4.14 4.8 $ — Options Exercisable December 31, 2016 313,505 $ 10.31 1.2 $ —
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, 2016 and 2015 are as follows: Year Ended December 31, 2016 2015 Expected dividend yield 0% 0% Expected stock price volatility 87.8% - 96.5% 56.4% - 59.5% Risk-free interest rate 1.1% - 1.5% 1.2% - 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, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 12/31/16 Weighted-Average Exercise Price Number Exercisable At 12/31/16 Weighted-Average Exercise Price $ 0.97 37,500 $ 0.97 — $ — $ 1.69 753,428 $ 1.69 — $ — $ 4.05 40,000 $ 4.05 — $ — $ 4.90 40,000 $ 4.90 3,333 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,181,100 $ 4.14 313,505 $ 10.31
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 Year Ended December 31, 2014 Expected Dividend Yield 0.0 % 0.0 % Risk-Free Interest Rate 1.0 % 0.8 % Expected Volatility – Rex Energy 58.6 % 50.4 % Expected Volatility – Peer Group 29.8%-85.0% 28.4%-65.7% Market Index 35.6 % 35.3 % Expected Life Three Years Three Years
Summary of Nonvested Restricted Stock Activity	A summary of the restricted stock activity for the years ended December 31, 2016, 2015 and 2014 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of January 1, 2014 2,172,639 $ 14.16 Awards 131,610 8.76 Vested (595,085 ) 13.09 Forfeitures (189,863 ) 14.60 Restricted stock awards, as of December 31, 2014 1,519,301 $ 14.05 Awards 2,236,839 3.35 Vested (606,359 ) 9.39 Forfeitures (670,373 ) 11.33 Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 1,423,091 0.91 Vested (872,061 ) 7.33 Forfeitures (602,944 ) 6.73 Restricted stock awards, as of December 31, 2016 2,427,494 $ 2.63

Suspended Exploratory Well Co44

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2016
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 the years ended December 31, 2016, 2015 and 2014 ($ in thousands): 2016 2015 2014 Beginning Balance at January 1, $ 16,970 $ 22,573 $ 5,517 Additions to capitalized exploratory well costs pending the determination of estimated proved reserves 46,759 144,333 252,115 Divested wells — — — Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves (39,126 ) (147,054 ) (235,039 ) Capitalized exploratory well costs charged to expense (7,402 ) (2,882 ) (20 ) Ending Balance at December 31, 17,201 16,970 22,573 Less exploratory well costs that have been capitalized for a period of one year or less (17,201 ) (12,049 ) (19,879 ) Capitalized exploratory well costs for a period of greater than one year $ — $ 4,921 $ 2,694 Number of projects that have exploratory well costs capitalized for a period of more than one year — 13 6

Costs Incurred In Oil And Nat45

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities (Tables)	12 Months Ended
	Dec. 31, 2016
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): 2016 2015 2014 Consolidated Entities: Acquisition of Properties Proved $ — $ — $ 161 Unproved 6,671 27,933 165,655 Exploration Costs(a) 24,650 157,067 306,752 Development Costs(a) 11,166 17,336 35,996 Subtotal 42,487 202,336 508,564 Asset Retirement Obligations 1,927 2,739 1,792 Total Costs Incurred $ 44,414 $ 205,075 $ 510,356 Share of Equity Method Investments: Acquisition of Properties Proved $ — $ — $ — Unproved — — — Exploration Costs — — — Development Costs(a) 793 824 438 Total $ 793 $ 824 $ 438 (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): 2016 2015 2014 Total Costs Incurred by Consolidated Entities $ 44,414 $ 205,075 $ 510,356 Illinois Basin Expenditures — 15,405 55,941 Exploration Expense (2,178 ) (2,617 ) (9,446 ) Asset Retirement Obligations (1,927 ) (2,739 ) (1,792 ) Depreciation for Support Equipment and Facilities — (4,905 ) (6,075 ) Corporate Expenditures — 231 869 Other (a) — (16,522 ) 7,223 Total Capital Expenditures $ 40,309 $ 193,928 $ 557,076 (a) Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and BSP and intercompany capital transactions.

Oil And Natural Gas Capitaliz46

Oil And Natural Gas Capitalized Costs (Tables)	12 Months Ended
	Dec. 31, 2016
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): 2016 2015 Consolidated Entities: Proven Oil and Natural Gas Properties $ 1,055,467 $ 943,092 Pipelines and Support Equipment 21,088 16,135 Field Operation Vehicles and Other Equipment 11,239 10,667 Wells and Facilities in Progress 21,964 140,953 Unproven Properties 215,794 262,992 Total 1,325,552 1,373,839 Less Accumulated Depreciation and Depletion (474,046 ) (427,321 ) Total $ 851,506 $ 946,518 Share of Equity Method Investments: Pipelines and Support Equipment 19,962 19,970 Wells and Facilities in Progress — — Total 19,962 19,970 Less Accumulated Depreciation and Depletion (4,211 ) (3,411 ) Total $ 15,751 $ 16,559

Oil and Natural Gas Reserve Q47

Oil and Natural Gas Reserve Quantities (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016, 2015 and 2014. 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. 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 ) (46,809.3 ) Production (360.4 ) (4,107.4 ) (44,618.1 ) (71,424.9 ) Estimated Proved Reserves-End of Period 1,866.0 44,824.4 367,640.9 647,783.3 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 ) Sales of Reserves (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 2014 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 8,619.6 46,130.7 521,282.8 849,784.6 Extensions, Discoveries and Additions 1,723.1 31,160.3 326,464.2 523,764.6 Revisions of Previous Estimates 471.1 (2,889.1 ) 9,971.0 (4,537.0 ) Purchases 12.0 933.0 18,478.3 24,148.3 Production (1,141.1 ) (2,082.4 ) (37,011.2 ) (56,352.2 ) Estimated Proved Reserves-End of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) (MMcf) Equivalents Proved Developed Reserves 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 December 31, 2014 7,628.1 29,215.0 365,673.3 586,731.9 Proved Undeveloped Reserves December 31, 2016 — — — — December 31, 2015 372.5 2,404.7 16,708.4 33,371.6 December 31, 2014 2,056.6 44,037.5 473,511.8 750,076.4

Standardized Measure Of Disco48

Standardized Measure Of Discounted Future Net Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2016
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 proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2016, 2015 and 2014 ($ in thousands): 2016 2015 2014 Future Cash Inflows $ 1,371,210 (a) $ 1,716,131 (b) $ 5,824,231 (c) Future Costs: Production (1,061,275 ) (1,144,049 ) (2,332,151 ) Abandonment (47,159 ) (143,459 ) (134,308 ) Development — (18,952 ) (686,676 ) Net Future Cash Inflow Before Income Taxes 262,776 409,671 2,671,096 Future Income Tax Expense — — (468,597 ) Total Future Net Cash Flows Before 10.0% Discount 262,776 409,671 2,202,499 Less: Effect of 10.0% Discount Factor (97,179 ) (154,048 ) (1,177,135 ) Standardized Measure of Discounted Future Net Cash Flows $ 165,597 $ 255,623 $ 1,025,364 (a) Calculated using weighted average prices of $2.264 per Mcf, $36.68 per barrel of oil and $10.50 per barrel of NGLs (b) Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs (c) Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 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: 2016 2015 2014 Standardized Measure – Beginning of Period $ 255,623 $ 1,025,364 $ 529,113 Revisions of Previous Estimates: Changes in Prices and Production Costs (89,583 ) (1,296,866 ) 253,865 Revisions in Quantities 9,851 (270,673 ) (5,970 ) Changes in Future Development Costs 7,786 595,547 (51,794 ) Accretion of Discount and Timing of Future Cash Flows 25,562 116,514 64,013 Net Change in Income Tax — 139,776 28,756 Purchase (Sale) of Reserves in Place (54,598 ) (37,101 ) 28,316 Plus Extensions, Discoveries, and Other Additions 21,841 88,152 430,252 Development Costs Incurred 11,166 31,574 71,383 Sales of Product – Net of Production Costs (34,301 ) (52,952 ) (197,587 ) Changes in Timing and Other 12,250 (83,712 ) (124,983 ) Standardized Measure – End of Period $ 165,597 $ 255,623 $ 1,025,364

Results Of Operations For Oil49

Results Of Operations For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2016
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): 2016 2015 2014 Consolidated Entities (in thousands): Revenues Oil and Natural Gas Sales $ 139,017 $ 138,749 $ 225,629 Expenses Production and Lease Operating Expense 104,699 93,892 69,547 Impairment Expense 74,619 283,244 20,225 Exploration Expense 2,178 2,617 6,813 Depletion, Depreciation, Amortization and Accretion 62,874 85,844 65,817 Total Costs 244,370 465,597 162,402 Pre-Tax Operating Income (Loss) (105,353 ) (326,848 ) 63,227 Income Tax Expense (a) (1,317 ) (5,687 ) (30,602 ) Results of Operations for Oil and Gas Producing Activities $ (106,670 ) $ (332,535 ) $ 32,625 Share of Equity Method Investments (in thousands): Expenses Depletion, Depreciation, Amortization and Accretion $ 813 $ 812 $ 805 Total Costs 813 812 805 Pre-Tax Operating Loss (813 ) (812 ) (805 ) Income Tax (Expense) Benefit (a) (10 ) (14 ) 390 Results of Operations for Oil and Gas Producing Activities $ (823 ) $ (826 ) $ (415 ) Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities $ (107,493 ) $ (333,361 ) $ 32,210 ( a ) Computed using the effective rate for continuing operations for each period: -1.25% in 2016; -1.74% in 2015 and; 48.4% in 2014.

Selected Quarterly Financial 50

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 March June September December Revenues $ 25,686 $ 31,265 $ 34,039 $ 48,027 Impairment Expense 10,641 25,139 9,563 29,276 Other Costs and Expenses 67,696 59,037 40,953 94,349 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 $ (0.98 ) $ 0.24 $ (0.19 ) $ (0.78 ) Basic — Discontinued Operations (0.13 ) (0.02 ) 0.24 0.08 Basic — Net Income (Loss) $ (1.11 ) $ 0.22 $ 0.05 $ (0.69 ) Basic — Weighted Average Shares Outstanding 56,003 71,804 90,803 97,398 Diluted — Continuing Operations $ (0.98 ) $ 0.24 $ (0.19 ) $ (0.78 ) Diluted — Discontinued Operations (0.13 ) (0.02 ) 0.24 0.08 Diluted — Net Income (Loss) $ (1.11 ) $ 0.22 $ 0.05 $ (0.69 ) Diluted — Weighted Average Shares Outstanding 56,003 71,804 90,803 97,398 2015 March June September December Revenues $ 45,934 $ 35,784 $ 29,656 $ 27,375 Impairment Expense 6,848 117,839 85,193 73,364 Other Costs and Expenses 54,079 69,287 33,354 51,567 Net Loss From Continuing Operations (14,993 ) (151,342 ) (88,891 ) (97,556 ) Net Loss From Discontinued Operations, Net of Income Taxes (1,524 ) (461 ) (5,785 ) (481 ) Net Loss (16,517 ) (151,803 ) (94,676 ) (98,037 ) Net Income (Loss) Attributable to Noncontrolling Interests 1,297 949 (1 ) — Net Loss Attributable to Rex Energy (17,814 ) (152,752 ) (94,675 ) (98,037 ) Preferred Stock Dividends (2,415 ) (2,415 ) (2,415 ) (2,415 ) Net Loss Attributable to Common Shareholders $ (20,229 ) $ (155,167 ) $ (97,090 ) $ (100,452 ) Loss per Common Share Attributable to Rex Energy Common Shareholders: Basic — Continuing Operations $ (0.32 ) $ (2.84 ) $ (1.69 ) $ (1.84 ) Basic — Discontinued Operations (0.05 ) (0.03 ) (0.11 ) (0.01 ) Basic — Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Basic — Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342 Diluted — Continuing Operations $ (0.32 ) $ (2.84 ) $ (1.69 ) $ (1.84 ) Diluted — Discontinued Operations (0.05 ) (0.03 ) (0.11 ) (0 ) Diluted — Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Diluted — Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342

Condensed Consolidating Finan51

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
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, 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 650 — 1,223 — 1,873 Inventory, Prepaid Expenses and Other 2,521 — 25 — 2,546 Total Current Assets 29,474 — 4,301 — 33,775 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,053,461 — — — 1,053,461 Unevaluated Oil and Gas Properties 215,794 — — — 215,794 Other Property and Equipment 21,401 — — — 21,401 Wells and Facilities in Progress 21,964 — — — 21,964 Pipelines 18,029 — — — 18,029 Total Property and Equipment 1,330,649 — — — 1,330,649 Less: Accumulated Depreciation, Depletion and Amortization (475,205 ) — — — (475,205 ) Net Property and Equipment 855,444 — — — 855,444 Other Assets 2,492 — — — 2,492 Intercompany Receivables — — 1,035,713 (1,035,713 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 500 — 1,712 — 2,212 Total Assets $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 40,712 — — — $ 40,712 Current Maturities of Long-Term Debt 764 — — — 764 Accrued Liabilities 32,328 421 4,458 — 37,207 Short-Term Derivative Instruments 25,025 — — — 25,025 Total Current Liabilities 98,829 421 4,458 — 103,708 Long-Term Derivative Instruments 7,227 — — — 7,227 Senior Secured Line of Credit, Net of Issuance Costs — — 113,785 — 113,785 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges — — 641,762 — 641,762 Discount on Senior Notes – Net — — (3,601 ) — (3,601 ) 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 — — 95 — 95 Additional Paid-In Capital 177,144 — 650,584 (177,144 ) 650,584 Accumulated Earnings (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 BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ 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 $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 17,225 — 49 — 17,274 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Assets Held for Sale 52,111 1,040 — — 53,151 Inventory, Prepaid Expenses and Other 3,034 — 25 — 3,059 Total Current Assets 107,719 1,040 94 — 108,853 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 950,062 — — (6,970 ) 943,092 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 20,363 — — — 20,363 Wells and Facilities in Progress 141,370 — — (270 ) 141,100 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,390,948 — — (9,377 ) 1,381,571 Less: Accumulated Depreciation, Depletion and Amortization (434,046 ) — — 3,518 (430,528 ) Net Property and Equipment 956,902 — — (5,859 ) 951,043 Deferred Financing Costs and Other Assets—Net 2,501 — — — 2,501 Intercompany Receivables — — 1,070,548 (1,070,548 ) — Investment in Subsidiaries – Net (1,907 ) — 243,331 (241,424 ) — Long-Term Derivative Instruments 9,534 — — — 9,534 Total Assets $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 36,785 $ — $ — $ — $ 36,785 Current Maturities of Long-Term Debt 402 — — — 402 Accrued Liabilities 28,883 — 11,725 — 40,608 Short-Term Derivative Instruments 2,486 — — — 2,486 Liabilities Related to Assets Held For Sale 36,289 31 — — 36,320 Total Current Liabilities 104,845 31 11,725 — 116,601 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 18 — 109,368 — 109,386 Senior Notes, Net of Issuance Costs — — 663,089 — 663,089 Premium on Senior Notes – Net — — 2,344 — 2,344 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 11,159 409 — — 11,568 Intercompany Payables 1,070,095 453 — (1,070,548 ) — Total Liabilities 1,194,829 893 786,526 (1,070,548 ) 911,700 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,143 — 619,777 (173,057 ) 623,863 Accumulated Earnings (Deficit) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931
Condensed Consolidating Statements of Operations	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 INCOME (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 0 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) Benefit (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 INCOME (LOSS) (146,290 ) (54 ) (176,715 ) 146,344 (176,715 ) Preferred Stock Dividends — — (5,091 ) — (5,091 ) Effect of Preferred Stock Conversions — — 72,984 — 72,984 NET INCOME (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 INCOME (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 0 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 Benefit (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 Tax (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 OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 225,511 $ — $ — $ — $ 225,511 Other Revenue 118 — — — 118 TOTAL OPERATING REVENUE 225,629 — — — 225,629 OPERATING EXPENSES Production and Lease Operating Expense 69,547 — — — 69,547 General and Administrative Expense 26,105 75 5,737 — 31,917 Loss on Disposal of Assets 218 — — — 218 Impairment Expense 14,269 5,956 — — 20,225 Exploration Expense 6,813 — — — 6,813 Depreciation, Depletion, Amortization and Accretion 65,816 1 — — 65,817 Other Operating Expense 312 — — — 312 TOTAL OPERATING EXPENSES 183,080 6,032 5,737 — 194,849 INCOME (LOSS) FROM OPERATIONS 42,549 (6,032 ) (5,737 ) — 30,780 OTHER INCOME (EXPENSE) Interest Expense (110 ) — (36,835 ) — (36,945 ) Gain on Derivatives, Net 37,359 — 1,517 — 38,876 Other Income (Expense) 73 — — — 73 Loss From Equity Method Investments (813 ) — — — (813 ) Income (Loss) From Equity in Consolidated Subsidiaries (3,131 ) 3,131 (25,250 ) 25,250 — TOTAL OTHER INCOME (EXPENSE) 33,378 3,131 (60,568 ) 25,250 1,191 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX 75,927 (2,901 ) (66,305 ) 25,250 31,971 Income Tax (Expense) Benefit (38,230 ) 2,917 19,853 — (15,460 ) NET INCOME (LOSS) FROM CONTINUING OPERATIONS 37,697 16 (46,452 ) 25,250 16,511 Income (Loss) From Discontinued Operations, Net of Income Taxes (63,582 ) 4,658 (237 ) — (59,161 ) NET INCOME (LOSS) (25,885 ) 4,674 (46,689 ) 25,250 (42,650 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 4,039 — — 4,039 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (25,885 ) $ 635 $ (46,689 ) $ 25,250 $ (46,689 ) Preferred Stock Dividends — — (2,335 ) — (2,335 ) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (25,885 ) $ 635 $ (49,024 ) $ 25,250 $ (49,024 )
Condensed Consolidating Statements of Cash Flows	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 Income (Loss) $ (146,290 ) $ (54 ) $ (176,715 ) $ 146,344 $ (176,715 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (212 ) 3 24,333 — 24,124 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 Dry Hole Expense 905 — — — 905 Gain on Extinguishment of Debt — — (24,627 ) — (24,627 ) (Gain) Loss on Sale of Assets (34,697 ) 46 — — (34,651 ) Impairment Expense 78,160 2 78,162 (78,162 ) 78,162 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 (1,950 ) — — — (1,950 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES (3,946 ) (806 ) (67,834 ) 68,182 (4,404 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 3,628 (94 ) 64,648 (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 (USED IN) INVESTING ACTIVITIES 7,379 806 64,648 (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 ) Dividends Paid on Preferred Stock — NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (828 ) — 3,187 — 2,359 NET (DECREASE) 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 by Operating Activities Loss on Equity Method Investments 411 — — — 411 Non-Cash Expenses (Income) (201 ) (334 ) 8,184 — 7,649 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 Dry Hole Expense 199 136 — (5 ) 330 Gain on Sale of Assets (477 ) (44 ) — — (521 ) Gain on Sale of Water Solutions — — (57,778 ) — (57,778 ) Impairment Expense 345,892 1,396 345,892 (347,405 ) 345,775 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 BY (USED IN) OPERATING ACTIVITIES 103,325 36,717 (67,034 ) (42,123 ) 30,885 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 96,763 (37,424 ) (100,298 ) 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 BY (USED IN) INVESTING ACTIVITIES (119,215 ) (44,956 ) (33,398 ) 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 ) Distributions by the Partners of Consolidated Subsidiary — (830 ) — — (830 ) Dividends Paid on Preferred Stock — — (9,660 ) — (9,660 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (999 ) 8,126 100,429 — 107,556 NET (DECREASE) IN CASH (16,889 ) (113 ) (3 ) 0 (17,005 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH - ENDING $ 1,089 $ 0 $ 2 $ 0 $ 1,091 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (25,885 ) $ 4,674 $ (46,689 ) $ 25,250 $ (42,650 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 813 — — — 813 Non-Cash Expenses (Income) (273 ) 278 6,784 — 6,789 Depreciation, Depletion, Amortization and Accretion 94,643 4,217 — (689 ) 98,171 Deferred Income Tax Benefit (9,928 ) (1,649 ) (14,415 ) — (25,992 ) Gain on Derivatives (37,359 ) — (1,517 ) — (38,876 ) Cash Settlements of Derivatives 5,969 — 1,312 — 7,281 Dry Hole Expense 3,797 267 — — 4,064 (Gain) Loss on Sale of Assets 644 (55 ) — — 589 Impairment Expense 126,662 6,022 — — 132,684 Changes in operating assets and liabilities Accounts Receivable (11,450 ) (6,090 ) 4,686 (766 ) (13,620 ) Inventory, Prepaid Expenses and Other Assets (1,283 ) (74 ) (2 ) — (1,359 ) Accounts Payable and Accrued Liabilities 23,768 3,488 9,252 766 37,274 Other Assets and Liabilities (2,127 ) (335 ) — — (2,462 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 167,992 10,743 (40,589 ) 24,561 162,706 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 401,412 (756 ) (371,768 ) (28,888 ) — Proceeds from Joint Venture Acreage Management 263 — — — 263 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 254 292 — — 546 Acquisitions of Undeveloped Acreage (168,713 ) (710 ) — — (169,423 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (382,889 ) (12,861 ) — 4,328 (391,422 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (149,673 ) (14,035 ) (371,768 ) (24,560 ) (560,036 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 38,895 171,000 — 209,895 Repayments of Long-Term Debt and Lines of Credit — (33,152 ) (230,000 ) — (263,152 ) Repayments of Loans and Other Notes Payable (1,727 ) (994 ) — — (2,721 ) Proceeds from Senior Notes, net of Discounts and Premiums — — 325,000 — 325,000 Debt Issuance Costs — (8 ) (6,816 ) — (6,824 ) Proceeds from Issuance of Preferred Stock, Net — — 154,988 — 154,988 Proceeds from the Exercise of Stock Options — — 515 — 515 Purchase of Non-Controlling Interests — (1,840 ) — — (1,840 ) Dividends Paid on Preferred Stock — — (2,335 ) — (2,335 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (1,727 ) 2,901 412,352 — 413,526 NET INCREASE (DECREASE) IN CASH 16,592 (391 ) (5 ) — 16,196 CASH – BEGINNING 1,386 504 10 — 1,900 CASH - ENDING $ 17,978 $ 113 $ 5 $ — $ 18,096

Basis of Presentation and Pri52

Basis of Presentation and Principles of Consolidation - Additional Information (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior secured line of credit and long term debt, net issuance costs		$ 113,785,000		$ 109,386,000
Senior notes, net of issuance costs	[1]	$ 641,762,000		663,089,000
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		$ 2,900,000
8.875% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Interest rate		8.875%	8.875%
Debt instrument maturity date		Dec. 1, 2020
6.25% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Interest rate		6.25%	6.25%
Debt instrument maturity date		Aug. 1, 2022
Accounting Standards Update201503
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior secured line of credit and long term debt, net issuance costs		$ 2,100,000		2,100,000
Senior notes, net of issuance costs		$ 11,900,000		11,900,000
Accounting Standards Update201503 | 8.875% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs				350,000,000
Accounting Standards Update201503 | 6.25% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs				325,000,000
Accounting Standards Update201517
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Long-term tax assets				12,500,000
Current deferred tax liability				12,500,000
Net deferred tax				$ 0
[1]	Includes unamortized debt issuance and financing costs of approximately ($7.9) million and $11.9 million as of December 31, 2016 and 2015, respectively.

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Additional Information (Details)		Jan. 01, 2016USD ($)	Dec. 31, 2016USD ($)shares	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)shares	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)Customershares	Dec. 31, 2015USD ($)Customershares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013shares
Accounting Policies [Line Items]
Allowance for bad debts			$ 100,000				$ 200,000				$ 100,000	$ 200,000
Accounts Receivable			25,448,000				17,274,000				$ 25,448,000	$ 17,274,000
Number of customers | Customer											3	3
Capitalized interest costs											$ 2,700,000	$ 7,700,000	$ 7,300,000
Impairment Expense			29,276,000	$ 9,563,000	$ 25,139,000	$ 10,641,000	73,364,000	$ 85,193,000	$ 117,839,000	$ 6,848,000	74,619,000	283,244,000	20,225,000
Accretion expense											985,000	967,000	700,000
Increase in estimated present value of asset retirement obligations											1,918,000	2,428,000
Future Abandonment Costs			$ 9,865,000				$ 11,934,000				$ 9,865,000	$ 11,934,000	$ 8,061,000
Income tax examination minimum likelihood of tax benefits being realized upon ultimate settlement											50.00%
Common Stock, shares outstanding | shares			97,870,608				55,741,229				97,870,608	55,741,229
Options outstanding | shares			1,181,100				443,672				1,181,100	443,672	402,561	449,087
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs			$ 113,785,000				$ 109,386,000				$ 113,785,000	$ 109,386,000
Senior notes, net of issuance costs	[1]		641,762,000				663,089,000				641,762,000	663,089,000
Income tax benefit											2,436,000	6,030,000	$ 15,460,000
Accounting Standards Update201503
Accounting Policies [Line Items]
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs			2,100,000				2,100,000				2,100,000	2,100,000
Senior notes, net of issuance costs			$ 11,900,000				11,900,000				$ 11,900,000	11,900,000
Accounting Standards Update201517
Accounting Policies [Line Items]
Long-term deferred tax assets							12,500,000					12,500,000
Current deferred tax liability							12,500,000					12,500,000
Net deferred tax							$ 0					$ 0
ASU 2016-09 | New Accounting Pronouncement, Early Adoption, Effect
Accounting Policies [Line Items]
Income tax benefit		$ 1,300,000
Stock Appreciation Rights (SARs)
Accounting Policies [Line Items]
Other than Options outstanding | shares			20,500								20,500
Restricted Stock
Accounting Policies [Line Items]
Other than Options outstanding | shares			2,427,494				2,479,408				2,427,494	2,479,408	1,519,301	2,172,639
Performance Shares
Accounting Policies [Line Items]
Other than Options outstanding | shares			617,479								617,479
Warrants
Accounting Policies [Line Items]
Share based compensation, warrants outstanding | shares			0								0
Accrued Liabilities
Accounting Policies [Line Items]
Future Abandonment Costs			$ 1,100,000				$ 400,000				$ 1,100,000	$ 400,000
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			2,700,000				3,200,000				$ 2,700,000	3,200,000
Condensate And Gas Production
Accounting Policies [Line Items]
Accounts Receivable			22,200,000				9,900,000				22,200,000	9,900,000
Condensate And Gas Production | Major Customers
Accounting Policies [Line Items]
Accounts Receivable			$ 17,500,000				$ 8,400,000				$ 17,500,000	$ 8,400,000
[1]	Includes unamortized debt issuance and financing costs of approximately ($7.9) million and $11.9 million as of December 31, 2016 and 2015, respectively.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$ 11,934	$ 8,061
Asset Retirement Obligation Incurred	575	1,063
Asset Retirement Obligation Settled	(671)	(449)
Asset Retirement Obligation Cancelled or Sold Properties	(4,876)	(136)
Asset Retirement Obligation Revision of Estimated Obligation	1,918	2,428
Asset Retirement Obligation Accretion Expense	985	967	$ 700
Total Future Abandonment Costs	$ 9,865	$ 11,934	$ 8,061

Business and Oil and Gas Prop55

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

Aug. 18, 2016USD ($)

Jun. 14, 2016USD ($)

May 20, 2016USD ($)Well

Mar. 01, 2016Well

Mar. 31, 2015USD ($)Well

Jul. 31, 2015USD ($)

Dec. 31, 2016USD ($)aWell

Jun. 30, 2016USD ($)

Dec. 31, 2016USD ($)aWellbbl

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Jun. 30, 2015USD ($)

Business Acquisition And Dispositions [Line Items]

Net proceeds from sale of property

$ 38,500,000

$ 0

Gain loss on sale of assets

$ 57,778,000

Payments for interest in wells that have been drilled or in process of being drilled

$ 48,982,000

$ 221,099,000

$ 391,422,000

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

Area of land held for sale | a

76,000

76,000

Number of barrels net production per day | bbl

1,700

Maximum

Business Acquisition And Dispositions [Line Items]

Additional proceeds from sale of oil and gas property and equipment

$ 9,900,000

Water Solutions Holdings, LLC

Business Acquisition And Dispositions [Line Items]

Ownership percentage by parent

60.00%

Aggregate consideration of Water Solutions

$ 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]

Total consideration for the transaction

$ 175,000,000

Amount received at closing of wells

126,100,000

Percentage of working interest

65.00%

Payments for interest in wells that have been drilled or in process of being drilled

$ 82,400,000

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

36

36

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

20

Number of producing wells | Well

30

30

Number of wells committed for line and producing | Well

42

42

Number of drilled well that is awaiting completion | Well

8

8

Number of wells in progress of being drilled | Well

4

4

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 | Maximum

Business Acquisition And Dispositions [Line Items]

Percentage of working interest earned in acreage

20.00%

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

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

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

Average Spot Price (Details)

Average Spot Price (Details)	12 Months Ended
	Dec. 31, 2016$ / bbl
3/31/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	56.25
6/30/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	58.25
9/30/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	60.25
12/31/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	60.75
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

Discontinued Operations_ Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
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

Summary of Financial Informatio

Summary of Financial Information for Discontinued Operations (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)bbl	Dec. 31, 2014USD ($)bbl
Revenues:
TOTAL OPERATING REVENUE	$ 48,027	$ 34,039	$ 31,265	$ 25,686	$ 27,375	$ 29,656	$ 35,784	$ 45,934	$ 139,017	$ 138,749	$ 225,629
Costs and Expenses:
Production and Lease Operating Expense									104,699	93,892	69,547
General and Administrative Expense									20,621	26,694	31,917
Depreciation, Depletion, Amortization and Accretion									62,874	85,844	65,817
Impairment Expense	$ 29,276	$ 9,563	$ 25,139	$ 10,641	$ 73,364	$ 85,193	$ 117,839	$ 6,848	74,619	283,244	20,225
Exploration Expense									2,178	2,617	6,813
(Gain) Loss on Disposal of Assets									(4,121)	(540)	218
Interest Expense									43,519	47,783	36,945
Other (Income) Expense									2,124	129	(73)
Income (Loss) from Discontinued Operations, net of taxes									20,922	(8,251)	(59,161)
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Revenues:
Field Services Revenue										33,086	58,627
TOTAL OPERATING REVENUE										33,086	58,627
Costs and Expenses:
General and Administrative Expense										1,961	4,081
Depreciation, Depletion, Amortization and Accretion										78	3,703
Impairment Expense											67
Field Service Operating Expense										25,981	44,369
(Gain) Loss on Disposal of Assets										(44)	(55)
Interest Expense										487	628
Other (Income) Expense										(57,589)	66
Total Costs and Expenses (Income)										(29,126)	52,859
Income from Discontinued Operations Before Income Taxes										62,212	5,768
Income Tax (Expense) Benefit										(24,227)	(768)
Income (Loss) from Discontinued Operations, net of taxes										37,985	5,000
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Revenues:
Oil Sales									11,282	33,244	72,359
TOTAL OPERATING REVENUE									11,282	33,244	72,359
Costs and Expenses:
Production and Lease Operating Expense									11,033	25,099	30,556
General and Administrative Expense									1,002	2,741	4,219
Depreciation, Depletion, Amortization and Accretion									5,100	18,900	28,650
Impairment Expense									3,543	62,531	112,394
Exploration Expense									143	394	2,633
(Gain) Loss on Disposal of Assets									(30,530)	63	426
Interest Expense									4	23	32
Other (Income) Expense									65	(14)	(16)
Total Costs and Expenses (Income)									(9,640)	109,737	178,894
Income from Discontinued Operations Before Income Taxes									20,922	(76,493)	(106,535)
Income Tax (Expense) Benefit										30,257	42,374
Income (Loss) from Discontinued Operations, net of taxes									$ 20,922	$ (46,236)	$ (64,161)
Production:
Crude Oil (Bbls) | bbl									310,388	729,251	806,162

Summary of Carrying Value of As

Summary of Carrying Value of Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets:
Cash and Cash Equivalents		$ 118
Total Current Assets	$ 53,151
Liabilities:
Total Liabilities Related to Assets Held for Sale	36,320
Illinois Basin Operations
Assets:
Accounts Receivable	2,209
Inventory, Prepaid Expenses and Other	770
Total Current Assets	2,979
Evaluated Oil & Gas Properties	296,338
Other Property and Equipment, Net	19,749
Wells and Facilities in Progress	3,456
Accumulated Depreciation, Depletion, and Amortization	(269,371)
Total Long-Term Assets	50,172
Total Assets Held for Sale	53,151
Liabilities:
Accounts Payable	1,089
Current Maturities of Long-Term Debt	188
Accrued Liabilities	3,718
Total Current Liabilities	4,995
Long-Term Debt	10
Future Abandonment Cost	31,315
Total Long-Term Liabilities	31,325
Total Liabilities Related to Assets Held for Sale	36,320
Net Assets Held for Sale:	$ 16,831

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule Of Equity Method Investments [Line Items]
Equity Method Investments							$ 0
Impairment Expense	$ 29,276,000	$ 9,563,000	$ 25,139,000	$ 10,641,000	$ 73,364,000	$ 85,193,000	$ 117,839,000	$ 6,848,000	$ 74,619,000	$ 283,244,000	$ 20,225,000
Loss on Equity Method Investments										(411,000)	(813,000)
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)

Concentrations of Credit Risk -

Concentrations of Credit Risk - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)CustomerEntity	Dec. 31, 2015USD ($)Customer
Concentration Risk [Line Items]
Federal Deposit Insurance Corporation's limit for cash balances	$ 250	$ 250
Number of Counterparties | Entity	6
Accounts Receivable	$ 25,448	$ 17,274
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	$ 22,200	$ 9,900
Customer Concentration Risk | Oil And Gas Production | Four Purchasers
Concentration Risk [Line Items]
Accounts Receivable	$ 17,500	$ 8,400

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	1 Months Ended		3 Months Ended	12 Months Ended
	Jan. 31, 2016USD ($)	Jan. 31, 2015USD ($)	Mar. 31, 2015Rigs	Dec. 31, 2016USD ($)Rigs	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Significant probable or possible environmental contingent liabilities				$ 0
Letters of credit				46,500,000	$ 41,000,000
Rent expense				900,000	1,000,000	$ 800,000
Termination fees incurred				4,800,000
Termination fees paid	$ 2,300,000	$ 2,500,000
Maximum guarantee of payment of obligations				402,400,000
Transportation, processing and marketing expenses of condensate, natural gas and natural gas liquids				91,700,000	79,500,000	55,400,000
Production and Lease Operating Expense				$ 104,699,000	93,892,000	69,547,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest				52.40%
Charges incurred for unutilized processing capacity				$ 3,200,000	600,000	200,000
Capacity Reservation | 2017
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,300,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,300,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,300,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,400,000
Capacity Reservation | 2021
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,300,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				$ 80,400,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations | Rigs				1
Number of contracts terminated | Rigs			2
Drilling Commitments | 2017
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs				$ 2,700,000
Drilling Commitments | 2018
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs				$ 1,800,000
Pennsylvania Impact Fee
Loss Contingencies [Line Items]
Rate in which unconventional wells are charged				20.00%
Production and Lease Operating Expense				$ 3,000,000	$ 3,000,000	$ 4,100,000
Natural Gas Transportation Agreements
Loss Contingencies [Line Items]
Letters of credit				$ 46,000,000

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Details) $ in Thousands	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 997
2,018	565
2,019	563
2,020	422
Total	$ 2,547

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 43,260
2,018	46,685
2,019	47,721
2,020	46,413
2,021	43,459
Thereafter	481,821
Total	$ 709,359

Fee for Unconventional Gas Well

Fee for Unconventional Gas Wells (Details) - Pennsylvania Impact Fee	12 Months Ended
	Dec. 31, 2016USD ($)	[1]
Less than $2.25
Unconventional Gas Wells [Line Items]
Year One	$ 40,200
Year Two	30,200
Year Three	25,200
Year 4 – 10	10,100
Year 11 – 15	5,000
$2.26 - $2.99
Unconventional Gas Wells [Line Items]
Year One	45,300
Year Two	35,200
Year Three	30,200
Year 4 – 10	15,100
Year 11 – 15	5,000
$3.00 - $4.99
Unconventional Gas Wells [Line Items]
Year One	50,300
Year Two	40,200
Year Three	30,200
Year 4 – 10	20,100
Year 11 – 15	10,100
$5.00 - $5.99
Unconventional Gas Wells [Line Items]
Year One	55,300
Year Two	45,300
Year Three	40,200
Year 4 – 10	20,100
Year 11 – 15	10,100
More than $5.99
Unconventional Gas Wells [Line Items]
Year One	60,400
Year Two	55,300
Year Three	50,300
Year 4 – 10	20,100
Year 11 – 15	$ 10,100
[1]	Pricing utilized for determining annual fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the year ending December 31.

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details)	Jun. 27, 2012USD ($)	Jun. 30, 2007USD ($)	Dec. 31, 2016USD ($)Aircraft$ / h	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Charlie Brown Air Corp
Related Party Transaction [Line Items]
Number of aircrafts in related party transaction | Aircraft			1
Payments for use of aircrafts			$ 0	$ 100,000	$ 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%
Percentage of loan guaranteed		50.00%
Amount of loan guaranteed		$ 800,000
Loan interest and retainer fees			$ 200,000	300,000	200,000
Charlie Brown Air Two LLC | Related Party Debt
Related Party Transaction [Line Items]
Bank loan		$ 1,500,000	$ 900,000	1,000,000
Maturity period of bank loan			Jun. 21, 2017
Amortization period of bank loan			180 months
Charlie Brown Air Two LLC | Related Party Debt | LIBOR
Related Party Transaction [Line Items]
Interest rate on bank loan		2.50%
Shaner Hotel Group Limited Partnership
Related Party Transaction [Line Items]
Percentage of membership interest			50.00%
Due to or from related party			$ 0
Annual CPI adjustment capped	2.50%
Shaner Office Holdings, L.P.
Related Party Transaction [Line Items]
Monthly rental payments	$ 35,000
Lease term	5 years
Operating lease annual rent			600,000
RW Gathering, LLC
Related Party Transaction [Line Items]
Due to or from related party			0	0	0
Production and Lease Operating Expense			$ 600,000	700,000	700,000
Ownership interest percentage			40.00%
Water Solutions Holding
Related Party Transaction [Line Items]
Water transfer and water purification expenses				6,100,000	20,100,000
Water transfer and water purification expenses eliminated in consolidation				4,700,000	$ 16,200,000
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 - Senior Credit

Long-Term Debt - Senior Credit Facility - Additional Information (Details) - USD ($)	Jan. 11, 2017	Aug. 18, 2016	Dec. 31, 2016	Dec. 31, 2016	Mar. 14, 2016	Dec. 31, 2015	Mar. 27, 2013
Debt Instrument [Line Items]
Line of credit facility, amount outstanding			$ 117,700,000	$ 117,700,000		$ 111,500,000
Effective rate				0.50%
Additional percentage with LIBOR				1.00%
Net proceeds from sale of property		$ 38,500,000	0
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity			46,500,000	$ 46,500,000
Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity			$ 190,000,000	$ 190,000,000
Line of credit facility, maturity date				Sep. 12, 2019
LIBOR rate description				The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 225 to 325 basis points, and in the case of loans bearing interest at the Alternate Base Rate, ranges from 125 to 225 basis points, in each case, determined based upon our borrowing base utilization at such date of determination
Percentage of reasonably anticipated projected production				85.00%
Liens covering the oil and gas properties, percentage					95.00%
Current ratio			100.00%	100.00%
Net senior secured debt to EBITDAX			262.00%	262.00%
Criteria senior secured debt to PDP coverage ratio			410.00%	410.00%
Expected capital expenditure for current fiscal year			$ 65,000,000	$ 65,000,000
Expected capital expenditure for next fiscal year			$ 65,000,000	$ 65,000,000
Expected senior secured debt to PDP coverage ratio up to next fiscal year			200.00%	200.00%
Senior Credit Facility | Moraine East and Warrior North
Debt Instrument [Line Items]
Liens covering the oil and gas properties, percentage					100.00%
Senior Credit Facility | Crude Oil (Bbls)
Debt Instrument [Line Items]
Percentage of reasonably anticipated projected production				75.00%
Senior Credit Facility | Natural Gas
Debt Instrument [Line Items]
Percentage of reasonably anticipated projected production				75.00%
Senior Credit Facility | Minimum
Debt Instrument [Line Items]
Percentage of purchase price of reserves for which interim borrowing base re-determinations may be requested							10.00%
Criteria Current ratio			100.00%	100.00%
Criteria senior secured debt to PDP coverage ratio			165.00%	165.00%
Senior Credit Facility | Minimum | LIBOR
Debt Instrument [Line Items]
Margin rate				2.25%
Senior Credit Facility | Minimum | Alternate Base Rate
Debt Instrument [Line Items]
Margin rate				1.25%
Senior Credit Facility | Maximum
Debt Instrument [Line Items]
Cash and cash equivalents			$ 15,000,000	$ 15,000,000
Duration of developed producing reserve				36 months
Outstanding principal amount of debt for borrowed money, percentage			75.00%	75.00%
Criteria of net senior secured debt to EBITDAX			275.00%	275.00%
Senior Credit Facility | Maximum | Interest Rate Swap
Debt Instrument [Line Items]
Notional amounts of interest rate swap			$ 20,000,000	$ 20,000,000
Senior Credit Facility | Maximum | LIBOR
Debt Instrument [Line Items]
Margin rate				3.25%
Senior Credit Facility | Maximum | Alternate Base Rate
Debt Instrument [Line Items]
Margin rate				2.25%
Senior Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity			$ 400,000,000	$ 400,000,000
Senior Credit Facility | Defaulted Loans
Debt Instrument [Line Items]
Margin rate				2.00%
Subsequent Event | Sale of Warrior South Assets
Debt Instrument [Line Items]
Net proceeds from sale of property	$ 24,100,000
Subsequent Event | Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, effective date	Jan. 11, 2017
Subsequent Event | Senior Credit Facility | Sale of Warrior South Assets
Debt Instrument [Line Items]
Net proceeds from sale of property	$ 24,100,000
Scenario One | Subsequent Event | Senior Credit Facility | Letter of Credit Including Surety Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	50,000,000
Scenario One | Subsequent Event | Senior Credit Facility | Surety Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, minimum borrowing capacity	10,000,000
Scenario Two | Subsequent Event | Senior Credit Facility | Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 40,000,000

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Details) - USD ($) $ / shares in Units, shares in Millions	Mar. 31, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 01, 2018
Debt Instrument [Line Items]
Aggregate share of common stock		10.1
Gain recognized due to exchanges			$ (9,063,000)
Aggregate 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			$ 2,983,000	$ 1,414,000	$ 6,824,000
Issuance of aggregate of unrestricted common stock shares	13.2		23.5
Gain on Extinguishments of Debt			$ 24,627,000
Gain per share on extinguishments of debt	$ 0.25
Senior Notes outstanding inclusive of net premium			638,200,000	677,300,000
Discount (premium) on Senior Notes outstanding, Net			3,601,000	(2,344,000)
Deferred financing costs			15,900,000	15,300,000
Amortization of net discount (premium)			$ 5,200,000	$ (400,000)
Trailing quarters fixed charge coverage ratio			225.00%
Fixed charge coverage ratio			102.00%
Senior Notes additional borrowings			$ 166,300,000
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
New Notes
Debt Instrument [Line Items]
Gain recognized due to exchanges		$ 0
Effective interest rate			6.06%
Interest rate	1.00%	1.00%
Aggregate principal amount	$ 633,200,000	$ 633,200,000
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
Debt amount for conversion	2,200,000
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%
New Notes | Troubled Debt Restructuring
Debt Instrument [Line Items]
Gain recognized due to exchanges	0
Debt instrument redemption amount	43,500,000
Debt amount for conversion	$ 10,900,000
New Notes | Interest Payments One Through Three
Debt Instrument [Line Items]
Interest rate	1.00%	1.00%
New Notes | Interest Payments Four And Thereafter
Debt Instrument [Line Items]
Interest rate	8.00%	8.00%
New Notes | Scenario Forecast
Debt Instrument [Line Items]
Interest rate						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%
Debt instrument redemption amount	$ 28,700,000
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%
8.875% Senior Notes
Debt Instrument [Line Items]
Interest rate	8.875%	8.875%	8.875%
Debt instrument maturity date			Dec. 1, 2020
6.25% Senior Notes
Debt Instrument [Line Items]
Interest rate	6.25%	6.25%	6.25%
Debt instrument maturity date			Aug. 1, 2022
Remaining Notes Outstanding Due to Holder With Debt-for-Equity Exchanges
Debt Instrument [Line Items]
Effective interest rate			1.16%

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges	[1]	$ 641,762	$ 663,089
Premium (Discount) on Senior Notes, Net		(3,601)	2,344
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs	[2],[3]	113,785	109,386
Capital Leases and Other Obligations	[3]	4,173	419
Total Debt		756,119	775,238
Less Current Portion of Long-Term Debt		(764)	(402)
Total Long-Term Debt		$ 755,355	$ 774,836
[1]	Includes unamortized debt issuance and financing costs of approximately ($7.9) million and $11.9 million as of December 31, 2016 and 2015, respectively.
[2]	Includes unamortized debt issuance costs of approximately $3.9 million and $2.1 million as of December 31, 2016 and 2015, respectively.
[3]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2016, 2015 and 2014 was approximately 3.8%, 1.7 % and 2.2%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2016, 2015 and 2014 was approximately 12.6%, 5.5% and 4.0%, respectively

Components of Long-Term Debt 70

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Senior Credit Facility
Debt Instrument [Line Items]
Average interest rate	3.80%	1.70%	2.20%
Capital Leases and Other Obligations
Debt Instrument [Line Items]
Average interest rate	12.60%	5.50%	4.00%
Senior Line of Credit
Debt Instrument [Line Items]
Unamortized debt issuance expense	$ 7.9	$ 11.9
Senior Secured Line of Credit and Long-Term Debt
Debt Instrument [Line Items]
Unamortized debt issuance expense	$ 3.9	$ 2.1

Principal Maturity Schedule for

Principal Maturity Schedule for Debt Outstanding (Details) $ in Thousands	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
2,017	$ 764
2,018	807
2,019	118,614
2,020	596,633
2,021	554
Thereafter	5,649
Total	$ 723,021	[1]
[1]	Does not include $3.6 million net discount on Senior Notes, $32.7 million of unamortized deferred gain on debt exchanges or ($4.0) million of amortization of deferred financing costs.

Principal Maturity Schedule f72

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
Senior notes, net discount	$ 3.6
Senior notes, Un amortized deferred gain	32.7
Amortization of deferred financing costs	$ (4)

Fair Value of Financial and Der

Fair Value of Financial and Derivative Instruments - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives	$ (32,571)	$ (55,793)	$ (7,281)
Senior Line of Credit	117,700	111,500
Senior Notes	601,200
Derivatives asset (liability)	28,200	35,800
Impairment Expense	$ 74,600
Crude Oil
Derivatives Fair Value [Line Items]
Commodity hedged percentage	65.00%
Illinois Basin Operations
Derivatives Fair Value [Line Items]
Fair value of contingent consideration derivative asset	$ 2,900
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Derivatives Fair Value [Line Items]
Fair value of contingent consideration derivative asset	$ 2,900
Natural Gas
Derivatives Fair Value [Line Items]
Commodity hedged percentage	75.00%
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Commodity hedged percentage	50.00%
Natural Gas Reserves Including Effects Of Derivatives Added Since December Thirty First Two Thousand Sixteen
Derivatives Fair Value [Line Items]
Commodity hedged percentage	80.00%
Natural Gas Liquids Reserves Including Effects Of Derivatives Added Since December Thirty First Two Thousand Sixteen
Derivatives Fair Value [Line Items]
Commodity hedged percentage	60.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives	$ 32,600	54,900	6,000
Changes in Fair Value	$ 7,249	(2,548)
Interest Rate Swap
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives		$ 900	$ 1,300

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (32,515)	$ 60,176	$ 38,876
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(1,515)	7,132	8,613
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	(15,036)	37,647	18,406
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(17,788)	14,839	10,340
Interest Rate Swap
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net		$ 934	$ 1,517
Contingent Consideration
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ 1,770

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / bbl$ / McfbblMcf	Dec. 31, 2015USD ($)
Crude Oil 2017 | Deferred Premium Put
Derivatives Fair Value [Line Items]
Volume | bbl	15,000
Floor | $ / bbl	51
Derivatives asset (liability)	$ (9)
Crude Oil 2017 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	48,000
Floor | $ / bbl	45
Ceiling | $ / bbl	57.20
Derivatives asset (liability)	$ (86)
Crude Oil 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	81,000
Swap | $ / bbl	53.30
Derivatives asset (liability)	$ (220)
Crude Oil 2017 | Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	93,000
Put Option | $ / bbl	40.16
Floor | $ / bbl	49.68
Ceiling | $ / bbl	61.50
Derivatives asset (liability)	$ (132)
Crude Oil 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	60,000
Swap | $ / bbl	54
Derivatives asset (liability)	$ (146)
Crude Oil 2018 | Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	60,000
Put Option | $ / bbl	43
Floor | $ / bbl	52
Ceiling | $ / bbl	62.30
Derivatives asset (liability)	$ (58)
Crude Oil
Derivatives Fair Value [Line Items]
Volume | bbl	357,000
Derivatives asset (liability)	$ (651)
Natural Gas 2017 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	1,700,000
Floor | $ / Mcf	2.54
Ceiling | $ / Mcf	3.20
Derivatives asset (liability)	$ (873)
Natural Gas 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	11,000,000
Swap | $ / Mcf	3.11
Derivatives asset (liability)	$ (4,468)
Natural Gas 2017 | Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	17,510,000
Put Option | $ / Mcf	2.33
Floor | $ / Mcf	3.01
Ceiling | $ / Mcf	3.87
Derivatives asset (liability)	$ (2,246)
Natural Gas 2017 | Swaptions
Derivatives Fair Value [Line Items]
Swap | $ / Mcf	3.15
Derivatives asset (liability)	$ (1,258)
Natural Gas 2017 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	3,900,000
Put Option | $ / Mcf	2.35
Swap | $ / Mcf	2.81
Derivatives asset (liability)	$ (3,303)
Natural Gas 2017 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	14,745,000
Swap | $ / Mcf	(0.86)
Derivatives asset (liability)	$ (53)
Natural Gas 2017 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ (355)
Natural Gas 2017 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	3,000,000
Ceiling | $ / Mcf	3.64
Derivatives asset (liability)	$ (1,478)
Natural Gas 2018 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	450,000
Floor | $ / bbl	3.20
Ceiling | $ / bbl	3.65
Derivatives asset (liability)	$ (115)
Natural Gas 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	5,510,000
Swap | $ / Mcf	3.25
Derivatives asset (liability)	$ (797)
Natural Gas 2018 | Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	8,775,000
Put Option | $ / Mcf	2.30
Floor | $ / Mcf	2.89
Ceiling | $ / Mcf	3.58
Derivatives asset (liability)	$ (1,786)
Natural Gas 2018 | Swaptions
Derivatives Fair Value [Line Items]
Swap | $ / Mcf	3.15
Derivatives asset (liability)	$ (167)
Natural Gas 2018 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	16,242,500
Swap | $ / Mcf	(0.82)
Derivatives asset (liability)	$ (193)
Natural Gas 2018 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ (355)
Natural Gas 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	5,810,000
Ceiling | $ / Mcf	3.97
Derivatives asset (liability)	$ (491)
Natural Gas 2019 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	16,242,500
Swap | $ / Mcf	(0.81)
Derivatives asset (liability)	$ (230)
Natural Gas 2020 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	13,542,000
Swap | $ / Mcf	(0.80)
Derivatives asset (liability)	$ (189)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	147,627,000
Derivatives asset (liability)	$ (18,357)
Natural Gas | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Derivatives asset (liability)		$ 5,468
Natural Gas | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Derivatives asset (liability)		$ 38
Natural Gas Liquids Reserves 2018 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	300,000
Swap | $ / bbl	13.02
Derivatives asset (liability)	$ (118)
Natural Gas Liquids Reserves 2018 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	852,000
Swap | $ / bbl	28.98
Derivatives asset (liability)	$ (2,082)
Natural Gas Liquids Reserves 2017 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	840,000
Swap | $ / bbl	10.50
Derivatives asset (liability)	$ (1,698)
Natural Gas Liquids Reserves 2017 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,337,000
Swap | $ / bbl	28.14
Derivatives asset (liability)	$ (8,197)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	3,329,000
Derivatives asset (liability)	$ (12,095)

Combined Fair Value of Derivati

Combined Fair Value of Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$ 1,873	$ 34,260
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	2,212	9,534
Total Derivative Assets	4,085	43,794
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(25,025)	(2,486)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(7,227)	(5,556)
Total Derivative Liabilities	(32,252)	(8,042)
Contingent Consideration | Sale of Illinois Basin
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,223
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,713
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		10,250
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		344
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(9,895)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(2,200)
Natural Gas | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		1,728
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(873)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(115)
Natural Gas | Three-Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	151	6,183
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		5,108
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(2,397)	(31)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(1,786)	(84)
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	206	9,010
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	206	1,593
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(4,673)	(292)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(1,004)
Natural Gas | Cap Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	61	1,977
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		2,294
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,364)
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	232	70
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	293	195
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(640)	(1,585)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(1,260)	(4,186)
Natural Gas | Swaptions
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		798
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(1,258)	(202)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(167)	(297)
Natural Gas | Put Spread
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		1,737
Natural Gas | Calls
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(1,478)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(491)	(989)
Crude Oil | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		1,078
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(86)
Crude Oil | Deferred Put Spread
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		852
Crude Oil | Three-Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		577
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(132)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(58)
Crude Oil | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(220)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(146)
Crude Oil | Deferred Premium Put
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	$ (9)
Refined Products | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		$ (376)

Significant Unobservable Inputs

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Details) - Natural Gas $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / Mcf	Dec. 31, 2016USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability) | $		$ 18,357
Basis Swaps - Dominion South
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.74)
Derivatives asset (liability) | $	$ (5,468)
Basis Swaps - Dominion South | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.27)
Basis Swaps - Dominion South | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(1.08)
Basis Swaps - Texas Gas
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.12)
Derivatives asset (liability) | $	$ (38)
Basis Swaps - Texas Gas | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.05)
Basis Swaps - Texas Gas | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.17)

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, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (28,167)	$ 35,752
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (28,167)	41,258
Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)		$ (5,506)

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, 2016	Dec. 31, 2015
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance of Level 3	$ (5,506)	$ 1,341
Changes in Fair Value	7,249	(2,548)
Transfers out of Level 3	(1,564)	0
Purchases	0	0
Settlements Received	(179)	(4,299)
Ending Balance of Level 3	$ 0	$ (5,506)

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Carrying Amount
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	$ 641,762	$ 663,089
Secured Lines of Credit	113,785	109,396
Capital Leases and Other Obligations	4,173	419
Total	759,720	772,904
Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	147,605	137,402
Secured Lines of Credit	113,785	109,396
Capital Leases and Other Obligations	3,234	411
Total	$ 264,624	$ 247,209

Income Tax Expense from Continu

Income Tax Expense from Continuing Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
Federal	$ 1,839
State	597		$ 10
Deferred:
Federal		$ 5,773	13,094
State		257	2,356
Income Tax Expense	$ 2,436	$ 6,030	$ 15,460

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income (Loss) from continuing operations before noncontrolling interests and income taxes	$ (195,201)	$ (346,752)	$ 31,971
Statutory U.S. income tax rate	35.00%	35.00%	35.00%
Tax expense recognized using statutory U.S. income tax rate	$ (68,320)	$ (121,363)	$ 11,190
State income taxes, net of federal income tax benefit	(3,632)	(17,137)	1,626
Change in estimated future state rates	(400)	(212)	(743)
Permanent differences	2,264	1,784	1,014
Change in valuation allowances	72,784	143,566	2,450
Other	(260)	(608)	(77)
Income Tax Expense	$ 2,436	$ 6,030	$ 15,460
Effective income tax rate	(1.25%)	(1.74%)	48.40%

Components of Deferred Tax Asse

Components of Deferred Tax Assets (Liabilities) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Assets:
Asset retirement obligation		$ 3,955	$ 17,831	[1]
Deferred compensation plans		1,581	3,111	[1]
Compensation Accruals		762	767	[1]
Unrealized loss on derivatives		11,760
Tax basis of oil and gas properties in excess of book basis	[1]		8,965
Net operating loss carryforwards	[1]	79,531	123,488
Deferred Financing Costs	[2]	182,519
Gas Transportation Capacity Commitments		3,031
Deferred revenue timing differences		443	969	[1]
Organization costs		391	456	[1]
Percentage depletion carryforward		2,717	2,673	[1]
AMT credits		2,131	292	[1]
Timing differences - tax partnerships		1,046	4,166	[1]
Other		331	372	[1]
Valuation allowances		(212,041)	(148,159)	[1],[3]
Total Deferred Tax Assets net of Valuation Allowances		78,157	14,931	[1]
Liabilities:
Book basis of oil and gas properties in excess of tax basis		(77,690)
Unrealized gain on derivatives	[1]		(14,144)
Other		(467)	(787)	[1]
Total Deferred Tax Liabilities		$ (78,157)	$ (14,931)	[1]
[1]	As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities for the year ended December 31, 2015 does not include $1.3 million of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting.
[2]	Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016.
[3]	Includes approximately $11.3 million of valuation allowances recorded to offset deferred tax assets attributes of our discontinued operations.

Components of Deferred Tax As84

Components of Deferred Tax Assets (Liabilities) (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Deferred Tax Assets And Liabilities [Line Items]
Excess tax benefit from share-based compensation	$ 1,300	$ 1,300
Valuation allowance for deferred tax assets	$ 212,041	148,159	[1],[2]
Discontinued Operations [Member]
Schedule Of Deferred Tax Assets And Liabilities [Line Items]
Valuation allowance for deferred tax assets		$ 11,300
[1]	As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities for the year ended December 31, 2015 does not include $1.3 million of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting.
[2]	Includes approximately $11.3 million of valuation allowances recorded to offset deferred tax assets attributes of our discontinued operations.

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)		Jan. 01, 2016	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Income Tax Disclosure [Line Items]
Deferred Financing Costs	[1]		$ 182,519,000
Income tax benefit recognized			2,436,000	$ 6,030,000		$ 15,460,000
Valuation allowance for deferred tax assets			212,041,000	148,159,000	[2],[3]
Net operating loss carryforwards, federal			152,200,000
Net operating loss carryforwards. state			416,500,000
Estimated annual utilization limit on net operating losses			1,400,000
Accrued interest and penalties relating to unrecognized tax benefits			$ 0	$ 0
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			2,036
ASU 2016-09 | New Accounting Pronouncement, Early Adoption, Effect
Income Tax Disclosure [Line Items]
Income tax benefit recognized		$ 1,300,000
[1]	Reflects book versus tax timing differences in the future amortization of deferred financing costs on debt exchanges completed in 2016.
[2]	As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities for the year ended December 31, 2015 does not include $1.3 million of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting.
[3]	Includes approximately $11.3 million of valuation allowances recorded to offset deferred tax assets attributes of our discontinued operations.

Expirations by Year for Federal

Expirations by Year for Federal and State Net Operating Loss Carryforwards (Details) - Federal and state $ in Thousands	Dec. 31, 2016USD ($)
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	$ 79,531
Expiration Year, 2023
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	1
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	455
Expiration Year, 2027
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	968
Expiration Year, 2028
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	0
Expiration Year, 2029
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	0
Expiration Year, 2030
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	0
Expiration Year, 2031
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	1,522
Expiration Year, 2032
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	0
Expiration Year, 2033
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	12,653
Expiration Year, 2034
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	6,241
Expiration Year, 2035
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	45,296
Expiration Year, 2036
Operating Loss Carryforwards [Line Items]
Net Operating Loss Carryforwards	$ 12,395

Earnings Per Common Share - Add

Earnings Per Common Share - Additional Information (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	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	1.2	0.4	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	0.6	1.1	0.8

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Numerator:
Net Income (Loss) From Continuing Operations	$ (75,598)	$ (16,477)	$ (52,911)	$ (52,651)	$ (97,556)	$ (88,891)	$ (151,342)	$ (14,993)	$ (197,637)		$ (352,782)		$ 16,511
Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests	8,203	21,892	(1,683)	(7,490)	(481)	(5,785)	(461)	(1,524)	20,922		(10,496)		(63,200)
Less: Preferred Stock Dividends	(650)	(613)	(1,723)	(2,105)	(2,415)	(2,415)	(2,415)	(2,415)	(5,091)		(9,660)		(2,335)
Effect of Preferred Stock Conversions	668		72,316						72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	$ (100,452)	$ (97,090)	$ (155,167)	$ (20,229)	$ (108,822)		$ (372,938)		$ (49,024)
Denominator:
Weighted Average Common Shares Outstanding - Basic	97,398	90,803	71,804	56,003	54,342	53,936	54,118	54,370	79,256		54,392		53,150
Effect of Dilutive Securities:
Weighted Average Common Shares Outstanding - Diluted	97,398	90,803	71,804	56,003	54,342	53,936	54,118	54,370	79,256		54,392		53,150
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Income (Loss) From Continuing Operations	$ (0.78)	$ (0.19)	$ 0.24	$ (0.98)	$ (1.84)	$ (1.69)	$ (2.84)	$ (0.32)	$ (1.63)	[1]	$ (6.66)	[1]	$ 0.27	[1]
Basic — Net Income (Loss) From Discontinued Operations	0.08	0.24	(0.02)	(0.13)	(0.01)	(0.11)	(0.03)	(0.05)	0.26	[1]	(0.19)	[1]	(1.19)	[1]
Basic – Net Loss Attributable to Rex Energy Common Shareholders	(0.69)	0.05	0.22	(1.11)	(1.85)	(1.80)	(2.87)	(0.37)	(1.37)	[1]	(6.85)	[1]	(0.92)	[1]
Diluted — Net Income (Loss) From Continuing Operations	(0.78)	(0.19)	0.24	(0.98)	(1.84)	(1.69)	(2.84)	(0.32)	(1.63)	[1]	(6.66)	[1]	0.27	[1]
Diluted — Net Income (Loss) From Discontinued Operations	0.08	0.24	(0.02)	(0.13)	0	(0.11)	(0.03)	(0.05)	0.26	[1]	(0.19)	[1]	(1.19)	[1]
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$ (0.69)	$ 0.05	$ 0.22	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.37)	[1]	$ (6.85)	[1]	$ (0.92)	[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	Mar. 31, 2016	Feb. 29, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 12, 2014
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized				200,000,000	200,000,000
Preferred Stock, shares authorized				100,000	100,000
Common Stock, shares outstanding				97,870,608	55,741,229
Issuance of Common Stock in Debt Exchange (in shares)				8,400,000
Debt converted to common stock	13,200,000			23,500,000
Preferred Stock, par value				$ 0.001	$ 0.001
Preferred Stock, shares issued				3,987	16,100
Preferred Stock, shares outstanding				3,987	16,100
Preferred stock shares converted			10,100,000
Dividends declared on Preferred Stock					$ 9,660	$ 2,335
Common Stock
Schedule Of Capitalization Equity [Line Items]
Issuance of Common Stock in Debt Exchange (in shares)				8,413,000
Preferred stock convertible preferred stock				9,300,000
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	16,100
Preferred Stock, shares outstanding				3,987	16,100
Preferred stock shares converted				12,113
Dividend per share in amount				$ 600
Dividend per share percentage				6.00%
Quarterly cash dividend paid per share		$ 0
Accumulated dividends in arrears				$ 5,000
Dividends declared on Preferred Stock					$ 9,700
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				5.5556
Common Stock
Schedule Of Capitalization Equity [Line Items]
Preferred stock to common stock conversion ratio				555.56

Major Customers - Additional In

Major Customers - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)Customer	Dec. 31, 2015USD ($)Customer	Dec. 31, 2014USD ($)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	4
Sales | Largest single purchaser
Revenue, Major Customer [Line Items]
Sales revenue | $	$ 55.1	$ 76	$ 96.4
Sales | Customer Concentration Risk | Four Purchasers
Revenue, Major Customer [Line Items]
Sales revenue | $	$ 95.1	$ 120	$ 206.1
Percentage of revenue from major customers	78.80%	82.20%	92.20%
Sales | Customer Concentration Risk | Largest single purchaser
Revenue, Major Customer [Line Items]
Percentage of revenue from major customers	45.60%	52.00%	43.10%

Employee Benefit and Equity P91

Employee Benefit and Equity Plans - Additional Information (Details) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015USD ($)shares	Dec. 31, 2016USD ($)Employees$ / sharesshares	Dec. 31, 2015USD ($)EntityEmployees$ / sharesshares	Dec. 31, 2014USD ($)Entity$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employer contribution to the plan			$ 0.5	$ 0.5
Number of option issued to purchase common stock | shares		888,922	80,000
Intrinsic value of stock options exercised				0.3
Total tax benefit				$ 0.1
Stock options exercised | shares		0	0	46,526
Outstanding weighted average remaining term (in years)		4 years 9 months 18 days	2 years 1 month 6 days
Weighted average remaining term of options exercisable (in years)		1 year 2 months 12 days
Unrecognized compensation expense		$ 0.3
Restricted Stock or Unit Expense	$ 2.5
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of employees | Employees		34	3
Share-based compensation		$ 0.4		$ 0.1
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation		2.7	$ 5.8	$ 5.4
Unrecognized compensation expense		$ 1.6
Common stock issued by compensation committee | shares		1,423,091	2,236,839	131,610
Number of companies in peer group | Entity			15	13
Fair value of TSR awards of per share estimated on date of grant | $ / shares		$ 0.91	$ 3.35	$ 8.76
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		$ 0.6	$ 2
Vested stock | shares		872,061	606,359	595,085
Restricted Stock | Certain Performance Factors Waived
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested stock | shares	189,872
Minimum | Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options		5 years
Maximum | Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options		10 years
2007 Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares authorized for issuance | shares		5,979,470,000
Shares available for grant | shares		2,385,791,000	1,144,297,000
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	$ 10.15

Summary of Stock Option Activit

Summary of Stock Option Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Beginning Balance, Number of Shares	443,672	402,561	449,087
Granted, Number of Shares	888,922	80,000
Exercised, Number of Shares	0	0	(46,526)
Cancelled/Forfeited, Number of Shares	(151,494)	(38,889)
Ending Balance, Number of Shares	1,181,100	443,672	402,561
Options Exercisable, Number of Shares	313,505
Beginning Balance, Weighted Average Exercise Price	$ 9.64	$ 10.82	$ 10.85
Granted, Weighted Average Exercise Price	1.66	4.48
Exercised, Weighted Average Exercise Price			11.09
Cancelled/Forfeited, Weighted Average Exercise Price	5.72	11.23
Ending Balance, Weighted Average Exercise Price	4.14	$ 9.64	$ 10.82
Options Exercisable, Weighted Average Exercise Price	$ 10.31
Options Outstanding December 31, Weighted Average Remaining Term (in years)	4 years 9 months 18 days	2 years 1 month 6 days
Options Exercisable December 31, Weighted Average Remaining Term (in years)	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, 2016	Dec. 31, 2015
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%	56.40%
Expected stock price volatility, maximum	96.50%	59.50%
Risk-free interest rate, minimum	1.10%	1.20%
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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding	1,181,100	443,672	402,561	449,087
Weighted-Average Exercise Price, Outstanding	$ 4.14	$ 9.64	$ 10.82	$ 10.85
Number Exercisable	313,505
Weighted-Average Exercise Price, Exercisable	$ 10.31
Exercise Price Range 0.97
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 0.97
Number Outstanding	37,500
Weighted-Average Exercise Price, Outstanding	$ 0.97
Exercise Price Range 1.69
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 1.69
Number Outstanding	753,428
Weighted-Average Exercise Price, Outstanding	$ 1.69
Exercise Price Range 4.05
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.05
Number Outstanding	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.05
Exercise Price Range 4.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.90
Number Outstanding	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.90
Number Exercisable	3,333
Weighted-Average Exercise Price, Exercisable	$ 4.90
Exercise Price Range 5.04
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 5.04
Number Outstanding	46,041
Weighted-Average Exercise Price, Outstanding	$ 5.04
Number Exercisable	46,041
Weighted-Average Exercise Price, Exercisable	$ 5.04
Exercise Price Range 9.50
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.50
Number Outstanding	75,000
Weighted-Average Exercise Price, Outstanding	$ 9.50
Number Exercisable	75,000
Weighted-Average Exercise Price, Exercisable	$ 9.50
Exercise Price Range 9.99
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.99
Number Outstanding	129,583
Weighted-Average Exercise Price, Outstanding	$ 9.99
Number Exercisable	129,583
Weighted-Average Exercise Price, Exercisable	$ 9.99
Exercise Price Range 10.42
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 10.42
Number Outstanding	29,548
Weighted-Average Exercise Price, Outstanding	$ 10.42
Number Exercisable	29,548
Weighted-Average Exercise Price, Exercisable	$ 10.42
Exercise Price Range 22.34
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 22.34
Number Outstanding	30,000
Weighted-Average Exercise Price, Outstanding	$ 22.34
Number Exercisable	30,000
Weighted-Average Exercise Price, Exercisable	$ 22.34

Percentage of Awards to Vest (D

Percentage of Awards to Vest (Details) - Restricted Stock	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Dividend Yield	0.00%	0.00%
Risk-Free Interest Rate	1.00%	0.80%
Expected Volatility	58.60%	50.40%
Market Index	35.60%	35.30%
Expected Life	3 years	3 years
Peer Group
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Volatility Rate Minimum	29.80%	28.40%
Expected Volatility Rate Maximum	85.00%	65.70%

Summary of Nonvested Stock Acti

Summary of Nonvested Stock Activity (Details) - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	2,479,408	1,519,301	2,172,639
Awards, Number of Shares	1,423,091	2,236,839	131,610
Vested, Number of Shares	(872,061)	(606,359)	(595,085)
Forfeitures, Number of Shares	(602,944)	(670,373)	(189,863)
Stock awards, ending balance, Number of Shares	2,427,494	2,479,408	1,519,301
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 6.27	$ 14.05	$ 14.16
Awards, Weighted Average Grant Date Fair Value	0.91	3.35	8.76
Vested, Weighted Average Grant Date Fair Value	7.33	9.39	13.09
Forfeitures, Weighted Average Grant Date Fair Value	6.73	11.33	14.60
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 2.63	$ 6.27	$ 14.05

Impairment Expense - Additional

Impairment Expense - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$ 29,276	$ 9,563	$ 25,139	$ 10,641	$ 73,364	$ 85,193	$ 117,839	$ 6,848	$ 74,619	$ 283,244	$ 20,225
RW Gathering, LLC
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense							$ 17,500
Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense										223,600	9,800
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
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense											3,600
Appalachian Basin | Regulatory and environmental climate
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense											5,900
Appalachian Basin | Unconventional Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense									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	$ 10,400
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									46,300
Marcellus and Utica Shale
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Unproved properties, cost	$ 215,800								$ 215,800

Net Change in Capitalized Explo

Net Change in Capitalized Exploratory Well Costs (Detail)	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)Project	Dec. 31, 2014USD ($)Project
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Beginning Balance at January 1,	$ 16,970,000	$ 22,573,000	$ 5,517,000
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves	46,759,000	144,333,000	252,115,000
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves	(39,126,000)	(147,054,000)	(235,039,000)
Capitalized exploratory well costs charged to expense	(7,402,000)	(2,882,000)	(20,000)
Ending Balance at December 31,	17,201,000	16,970,000	22,573,000
Less exploratory well costs that have been capitalized for a period of one year or less	(17,201,000)	(12,049,000)	(19,879,000)
Capitalized exploratory well costs for a period of greater than one year	$ 0	$ 4,921,000	$ 2,694,000
Number of projects that have exploratory well costs capitalized for a period of more than one year | Project		13	6

Suspended Exploratory Well C100

Suspended Exploratory Well Costs - Additional Information (Detail)	Dec. 31, 2016USD ($)Well	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory well costs for a period of greater than one year | $	$ 0	$ 4,921,000	$ 2,694,000
Pennsylvania Impact Fee
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory number of wells | Well	13

Costs Incurred in Oil and Na101

Costs Incurred in Oil and Natural Gas Property Acquisitions and Development (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Acquisition of Properties
Exploration Costs		$ 2,178	$ 2,617	$ 9,446
Development Costs			231	869
Subtotal		40,309	193,928	557,076
Asset Retirement Obligations		1,927	2,739	1,792
Total Costs Incurred		44,414	205,075	510,356
Consolidated Entities
Acquisition of Properties
Proved				161
Unproved		6,671	27,933	165,655
Exploration Costs	[1]	24,650	157,067	306,752
Development Costs	[1]	11,166	17,336	35,996
Subtotal		42,487	202,336	508,564
Asset Retirement Obligations		1,927	2,739	1,792
Total Costs Incurred		44,414	205,075	510,356
Equity Method Investee
Acquisition of Properties
Development Costs	[1]	793	824	438
Subtotal		$ 793	$ 824	$ 438
[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Total Costs Incurred		$ 44,414	$ 205,075	$ 510,356
Illinois Basin Expenditures			15,405	55,941
Exploration Expense		(2,178)	(2,617)	(9,446)
Asset Retirement Obligations		(1,927)	(2,739)	(1,792)
Depreciation for Support Equipment and Facilities			(4,905)	(6,075)
Corporate Expenditures			231	869
Other	[1]		(16,522)	7,223
Subtotal		$ 40,309	$ 193,928	$ 557,076
[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, 2016	Dec. 31, 2015
Consolidated Entities
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proven Oil and Natural Gas Properties	$ 1,055,467	$ 943,092
Pipelines and Support Equipment	21,088	16,135
Field Operation Vehicles and Other Equipment	11,239	10,667
Wells and Facilities in Progress	21,964	140,953
Unproven Properties	215,794	262,992
Total	1,325,552	1,373,839
Less Accumulated Depreciation and Depletion	(474,046)	(427,321)
Total	851,506	946,518
Equity Method Investee
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Pipelines and Support Equipment	19,962	19,970
Total	19,962	19,970
Less Accumulated Depreciation and Depletion	(4,211)	(3,411)
Total	$ 15,751	$ 16,559

Summary of Changes in Estimated

Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells (Details)	12 Months Ended
	Dec. 31, 2016MMcfebblMcf	Dec. 31, 2015MMcfebblMcf	Dec. 31, 2014MMcfebblMcf
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period | MMcfe	680,445,000	1,336,808,300	849,784,600
Extensions, Discoveries and Additions | MMcfe	26,427,800	142,986,700	523,764,600
Revisions of Previous Estimates | MMcfe	59,144,700	(703,020,300)	(4,537,000)
Sales of Reserves | MMcfe	(46,809,300)	(24,854,900)
Production | MMcfe	(71,424,900)	(71,474,800)	(56,352,200)
Estimated Proved Reserves-End of Period | MMcfe	647,783,300	680,445,000	1,336,808,300
Purchases | MMcfe			24,148,300
Proved Developed Reserves Energy Equivalents | MMcfe	647,783,100	647,073,400	586,731,900
Proved Undeveloped Reserves Energy Equivalents | MMcfe		33,371,600	750,076,400
Oil
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	5,317,100	9,684,700	8,619,600
Extensions, Discoveries and Additions	373,500	949,000	1,723,100
Revisions of Previous Estimates	323,900	(4,176,800)	471,100
Sales of Reserves	(3,788,100)	(7,700)
Production	(360,400)	(1,132,100)	(1,141,100)
Estimated Proved Reserves-End of Period	1,866,000	5,317,100	9,684,700
Purchases			12,000
Proved Developed Reserves	1,865,900	4,944,600	7,628,100
Proved Undeveloped Reserves		372,500	2,056,600
Natural Gas Liquids
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	40,346,600	73,252,500	46,130,700
Extensions, Discoveries and Additions	2,183,700	10,079,300	31,160,300
Revisions of Previous Estimates	8,262,000	(38,249,700)	(2,889,100)
Sales of Reserves	(1,860,500)	(1,389,600)
Production	(4,107,400)	(3,345,900)	(2,082,400)
Estimated Proved Reserves-End of Period	44,824,400	40,346,600	73,252,500
Purchases			933,000
Proved Developed Reserves	44,824,400	37,941,900	29,215,000
Proved Undeveloped Reserves		2,404,700	44,037,500
Natural Gas
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period | Mcf	406,462,800	839,185,100	521,282,800
Extensions, Discoveries and Additions | Mcf	11,084,600	76,816,900	326,464,200
Revisions of Previous Estimates | Mcf	7,629,300	(448,461,300)	9,971,000
Sales of Reserves | Mcf	(12,917,700)	(16,471,100)
Production | Mcf	(44,618,100)	(44,606,800)	(37,011,200)
Estimated Proved Reserves-End of Period | Mcf	367,640,900	406,462,800	839,185,100
Purchases | Mcf			18,478,300
Proved Developed Reserves | Mcf	367,641,300	389,754,400	365,673,300
Proved Undeveloped Reserves | Mcf		16,708,400	473,511,800

Oil and Natural Gas Reserve 105

Oil and Natural Gas Reserve Quantities - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016MMcfeMMBoe	Dec. 31, 2015MMcfeMMBoe	Dec. 31, 2014MMcfeMMBoe
Reserve Quantities [Line Items]
Discount rate	10.00%
Revisions	59,100
Crude Oil
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions | MMBoe	0.4	0.9	1.7
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions | MMBoe	2.2	10.1	31.2
Natural Gas
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions	11,100	76,800	326,500
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
Revisions			38,000
Well Performance
Reserve Quantities [Line Items]
Revisions | MMBoe		(2,200)
Proved Undeveloped with in Five Years
Reserve Quantities [Line Items]
Revisions			(58,500)
Commodity Pricing
Reserve Quantities [Line Items]
Revisions			(1,600)
Operating Expense
Reserve Quantities [Line Items]
Revisions		15,400
Revisions			17,600
Butler
Reserve Quantities [Line Items]
Revisions		10,300
Revisions			51,000
Warrior North Prospect in Ohio
Reserve Quantities [Line Items]
Revisions		9,800
Warrior South Prospect and Westmoreland
Reserve Quantities [Line Items]
Revisions			(15,500)
Marcellus and Utica Shale
Reserve Quantities [Line Items]
Percentage Of Proved Undeveloped Reserves Extensions Discoveries And Additions	100.00%

Standardized Measure of Disc106

Standardized Measure of Discounted Future Net Cash Flows - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016
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, 2016		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Future Cash Inflows	$ 1,371,210	[1]	$ 1,716,131	[2]	$ 5,824,231	[3]
Production	(1,061,275)		(1,144,049)		(2,332,151)
Abandonment	(47,159)		(143,459)		(134,308)
Development			(18,952)		(686,676)
Net Future Cash Inflow Before Income Taxes	262,776		409,671		2,671,096
Future Income Tax Expense					(468,597)
Total Future Net Cash Flows Before 10.0% Discount	262,776		409,671		2,202,499
Less: Effect of 10.0% Discount Factor	(97,179)		(154,048)		(1,177,135)
Standardized Measure of Discounted Future Net Cash Flows	$ 165,597		$ 255,623		$ 1,025,364		$ 529,113
[1]	Calculated using weighted average prices of $2.264 per Mcf, $36.68 per barrel of oil and $10.50 per barrel of NGLs
[2]	Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs
[3]	Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs

Summary of Future Net Cash F108

Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices | $ / Mcf	2.264	2.401	3.455
Crude Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices	36.68	44.45	88.02
Natural Gas Liquids
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices	10.50	12.48	28.30

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Standardized Measure – Beginning of Period	$ 255,623	$ 1,025,364	$ 529,113
Changes in Prices and Production Costs	(89,583)	(1,296,866)	253,865
Revisions in Quantities	9,851	(270,673)	(5,970)
Changes in Future Development Costs	7,786	595,547	(51,794)
Accretion of Discount and Timing of Future Cash Flows	25,562	116,514	64,013
Net Change in Income Tax		139,776	28,756
Purchase (Sale) of Reserves in Place	(54,598)	(37,101)	28,316
Plus Extensions, Discoveries, and Other Additions	21,841	88,152	430,252
Development Costs Incurred	11,166	31,574	71,383
Sales of Product – Net of Production Costs	(34,301)	(52,952)	(197,587)
Changes in Timing and Other	12,250	(83,712)	(124,983)
Standardized Measure – End of Period	$ 165,597	$ 255,623	$ 1,025,364

Results of Operations (Details)

Results of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Expenses
Results of Operations for Oil and Gas Producing Activities		$ (107,493)	$ (333,361)	$ 32,210
Consolidated Entities
Revenues
Oil and Natural Gas Sales		139,017	138,749	225,629
Expenses
Production and Lease Operating Expense		104,699	93,892	69,547
Impairment Expense		74,619	283,244	20,225
Exploration Expense		2,178	2,617	6,813
Depletion, Depreciation, Amortization and Accretion		62,874	85,844	65,817
Total Costs		244,370	465,597	162,402
Pre-Tax Operating Income (Loss)		(105,353)	(326,848)	63,227
Income Tax (Expense) Benefit	[1]	(1,317)	(5,687)	(30,602)
Results of Operations for Oil and Gas Producing Activities		(106,670)	(332,535)	32,625
Equity Method Investee
Expenses
Depletion, Depreciation, Amortization and Accretion		813	812	805
Total Costs		813	812	805
Pre-Tax Operating Income (Loss)		(813)	(812)	(805)
Income Tax (Expense) Benefit	[1]	(10)	(14)	390
Results of Operations for Oil and Gas Producing Activities		$ (823)	$ (826)	$ (415)
[1]	Computed using the effective rate for continuing operations for each period: -1.25% in 2016; -1.74% in 2015 and; 48.4% in 2014.

Results of Operations (Parenthe

Results of Operations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Effective tax rate	(1.25%)	(1.74%)	48.40%

Litigation - Additional Informa

Litigation - Additional Information (Details)	1 Months Ended		12 Months Ended
	Jul. 31, 2012Case	Oct. 31, 2011Plaintiff	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Number of plaintiffs | Plaintiff		2
Case dismissed date			2012-05
Case revised decision date			2013-05
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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 48,027	$ 34,039	$ 31,265	$ 25,686	$ 27,375	$ 29,656	$ 35,784	$ 45,934	$ 139,017		$ 138,749		$ 225,629
Impairment Expense	29,276	9,563	25,139	10,641	73,364	85,193	117,839	6,848	74,619		283,244		20,225
Other Costs and Expenses	94,349	40,953	59,037	67,696	51,567	33,354	69,287	54,079
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(75,598)	(16,477)	(52,911)	(52,651)	(97,556)	(88,891)	(151,342)	(14,993)	(197,637)		(352,782)		16,511
Net Income (Loss) From Discontinued Operations, Net of Income Taxes	8,203	21,892	(1,683)	(7,490)	(481)	(5,785)	(461)	(1,524)	20,922		(10,496)		(63,200)
NET LOSS					(98,037)	(94,676)	(151,803)	(16,517)	(176,715)		(361,033)		(42,650)
Net Income Attributable to Noncontrolling Interests						(1)	949	1,297			2,245		4,039
NET LOSS ATTRIBUTABLE TO REX ENERGY	(67,395)	5,415	(54,594)	(60,141)	(98,037)	(94,675)	(152,752)	(17,814)	(176,715)		(363,278)		(46,689)
Preferred Stock Dividends	(650)	(613)	(1,723)	(2,105)	(2,415)	(2,415)	(2,415)	(2,415)	(5,091)		(9,660)		(2,335)
Effect of Preferred Stock Conversions	668		72,316						72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	$ (100,452)	$ (97,090)	$ (155,167)	$ (20,229)	$ (108,822)		$ (372,938)		$ (49,024)
Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Continuing Operations	$ (0.78)	$ (0.19)	$ 0.24	$ (0.98)	$ (1.84)	$ (1.69)	$ (2.84)	$ (0.32)	$ (1.63)	[1]	$ (6.66)	[1]	$ 0.27	[1]
Basic — Net Income (Loss) From Discontinued Operations	0.08	0.24	(0.02)	(0.13)	(0.01)	(0.11)	(0.03)	(0.05)	0.26	[1]	(0.19)	[1]	(1.19)	[1]
Basic — Net Income (Loss)	$ (0.69)	$ 0.05	$ 0.22	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.37)	[1]	$ (6.85)	[1]	$ (0.92)	[1]
Basic – Weighted Average Shares of Common Stock Outstanding	97,398	90,803	71,804	56,003	54,342	53,936	54,118	54,370	79,256		54,392		53,150
Diluted — Continuing Operations	$ (0.78)	$ (0.19)	$ 0.24	$ (0.98)	$ (1.84)	$ (1.69)	$ (2.84)	$ (0.32)	$ (1.63)	[1]	$ (6.66)	[1]	$ 0.27	[1]
Diluted — Net Income (Loss) From Discontinued Operations	0.08	0.24	(0.02)	(0.13)	0	(0.11)	(0.03)	(0.05)	0.26	[1]	(0.19)	[1]	(1.19)	[1]
Diluted — Net Income (Loss)	$ (0.69)	$ 0.05	$ 0.22	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.37)	[1]	$ (6.85)	[1]	$ (0.92)	[1]
Diluted – Weighted Average Shares of Common Stock Outstanding	97,398	90,803	71,804	56,003	54,342	53,936	54,118	54,370	79,256		54,392		53,150
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Condensed Consolidating Fina114

Condensed Consolidating Financial Information - Additional Information (Details) $ in Millions	Dec. 31, 2016USD ($)
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Gross	$ 601.2

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Assets
Cash and Cash Equivalents		$ 3,697	$ 1,091	$ 17,978
Accounts Receivable		25,448	17,274
Taxes Receivable		211	18
Short-Term Derivative Instruments		1,873	34,260
Assets Held for Sale			53,151
Inventory, Prepaid Expenses and Other		2,546	3,059
Total Current Assets		33,775	108,853
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,053,461	943,092
Unevaluated Oil and Gas Properties		215,794	262,992
Other Property and Equipment		21,401	20,363
Wells and Facilities in Progress		21,964	141,100
Pipelines		18,029	14,024
Total Property and Equipment		1,330,649	1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(475,205)	(430,528)
Net Property and Equipment		855,444	951,043
Other Assets		2,492	2,501
Long-Term Derivative Instruments		2,212	9,534
Deferred Financing Costs and Other Assets—Net			2,501
Total Assets		893,923	1,071,931
Current Liabilities
Accounts Payable		40,712	36,785
Current Maturities of Long-Term Debt		764	402
Accrued Liabilities		37,207	40,608
Short-Term Derivative Instruments		25,025	2,486
Liabilities Related to Assets Held For Sale			36,320
Total Current Liabilities		103,708	116,601
Long-Term Derivative Instruments		7,227	5,556
Senior secured line of credit and long term debt, net issuance costs		113,785	109,386
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges	[1]	641,762	663,089
Premium (Discount) on Senior Notes, Net		(3,601)	2,344
Other Long-Term Debt		3,409
Other Deposits and Liabilities		8,671	3,156
Future Abandonment Cost		8,736	11,568
Total Liabilities		883,697	911,700
Stockholders’ Equity
Preferred Stock		1	1
Common Stock		95	54
Additional Paid-In Capital		650,584	623,863
Accumulated Earnings (Deficit)		(640,454)	(463,687)
Total Stockholders’ Equity		10,226	160,231	$ 531,373	$ 416,925
Total Liabilities and Stockholders’ Equity		893,923	1,071,931
Eliminations
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			(6,970)
Wells and Facilities in Progress			(270)
Pipelines			(2,137)
Total Property and Equipment			(9,377)
Less: Accumulated Depreciation, Depletion and Amortization			3,518
Net Property and Equipment			(5,859)
Intercompany Receivables		(1,035,713)	(1,070,548)
Investment in Subsidiaries – Net		130,362	(241,424)
Total Assets		(905,351)	(1,317,831)
Current Liabilities
Intercompany Payables		(1,035,713)	(1,070,548)
Total Liabilities		(1,035,713)	(1,070,548)
Stockholders’ Equity
Additional Paid-In Capital		(177,144)	(173,057)
Accumulated Earnings (Deficit)		307,506	(74,226)
Total Stockholders’ Equity		130,362	(247,283)
Total Liabilities and Stockholders’ Equity		(905,351)	(1,317,831)
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents		3,694	1,089
Accounts Receivable		22,609	17,225
Short-Term Derivative Instruments		650	34,260
Assets Held for Sale			52,111
Inventory, Prepaid Expenses and Other		2,521	3,034
Total Current Assets		29,474	107,719
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,053,461	950,062
Unevaluated Oil and Gas Properties		215,794	262,992
Other Property and Equipment		21,401	20,363
Wells and Facilities in Progress		21,964	141,370
Pipelines		18,029	16,161
Total Property and Equipment		1,330,649	1,390,948
Less: Accumulated Depreciation, Depletion and Amortization		(475,205)	(434,046)
Net Property and Equipment		855,444	956,902
Other Assets		2,492
Investment in Subsidiaries – Net		(2,388)	(1,907)
Long-Term Derivative Instruments		500	9,534
Deferred Financing Costs and Other Assets—Net			2,501
Total Assets		885,522	1,074,749
Current Liabilities
Accounts Payable		40,712	36,785
Current Maturities of Long-Term Debt		764	402
Accrued Liabilities		32,328	28,883
Short-Term Derivative Instruments		25,025	2,486
Liabilities Related to Assets Held For Sale			36,289
Total Current Liabilities		98,829	104,845
Long-Term Derivative Instruments		7,227	5,556
Senior secured line of credit and long term debt, net issuance costs			18
Other Long-Term Debt		3,409
Other Deposits and Liabilities		8,671	3,156
Future Abandonment Cost		8,736	11,159
Intercompany Payables		1,032,050	1,070,095
Total Liabilities		1,158,922	1,194,829
Stockholders’ Equity
Additional Paid-In Capital		177,144	177,143
Accumulated Earnings (Deficit)		(450,544)	(297,223)
Total Stockholders’ Equity		(273,400)	(120,080)
Total Liabilities and Stockholders’ Equity		885,522	1,074,749
Non-Guarantor Subsidiaries
Current Assets
Assets Held for Sale			1,040
Total Current Assets			1,040
Property and Equipment (Successful Efforts Method)
Total Assets			1,040
Current Liabilities
Accrued Liabilities		421
Liabilities Related to Assets Held For Sale			31
Total Current Liabilities		421	31
Future Abandonment Cost			409
Intercompany Payables		3,663	453
Total Liabilities		4,084	893
Stockholders’ Equity
Accumulated Earnings (Deficit)		(4,084)	147
Total Stockholders’ Equity		(4,084)	147
Total Liabilities and Stockholders’ Equity			1,040
Parent Company
Current Assets
Cash and Cash Equivalents		3	2
Accounts Receivable		2,839	49
Taxes Receivable		211	18
Short-Term Derivative Instruments		1,223
Inventory, Prepaid Expenses and Other		25	25
Total Current Assets		4,301	94
Property and Equipment (Successful Efforts Method)
Intercompany Receivables		1,035,713	1,070,548
Investment in Subsidiaries – Net		(127,974)	243,331
Long-Term Derivative Instruments		1,712
Total Assets		913,752	1,313,973
Current Liabilities
Accrued Liabilities		4,458	11,725
Total Current Liabilities		4,458	11,725
Senior secured line of credit and long term debt, net issuance costs		113,785	109,368
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges		641,762	663,089
Premium (Discount) on Senior Notes, Net		(3,601)	2,344
Total Liabilities		756,404	786,526
Stockholders’ Equity
Preferred Stock		1	1
Common Stock		95	54
Additional Paid-In Capital		650,584	619,777
Accumulated Earnings (Deficit)		(493,332)	(92,385)
Total Stockholders’ Equity		157,348	527,447
Total Liabilities and Stockholders’ Equity		$ 913,752	$ 1,313,973
[1]	Includes unamortized debt issuance and financing costs of approximately ($7.9) million and $11.9 million as of December 31, 2016 and 2015, respectively.

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales									$ 139,000	$ 138,707	$ 225,511
Other Revenue									17	42	118
TOTAL OPERATING REVENUE	$ 48,027	$ 34,039	$ 31,265	$ 25,686	$ 27,375	$ 29,656	$ 35,784	$ 45,934	139,017	138,749	225,629
OPERATING EXPENSES
Production and Lease Operating Expense									104,699	93,892	69,547
General and Administrative Expense									20,621	26,694	31,917
(Gain) Loss on Disposal of Assets									(4,121)	(540)	218
Impairment Expense	29,276	9,563	25,139	10,641	73,364	85,193	117,839	6,848	74,619	283,244	20,225
Exploration Expense									2,178	2,617	6,813
Depreciation, Depletion, Amortization and Accretion									62,874	85,844	65,817
Other Operating Expense									10,754	5,603	312
TOTAL OPERATING EXPENSES									271,624	497,354	194,849
INCOME (LOSS) FROM OPERATIONS									(132,607)	(358,605)	30,780
OTHER INCOME (EXPENSE)
Interest Expense									(43,519)	(47,783)	(36,945)
Gain (Loss) on Derivatives, Net									(32,515)	60,176	38,876
Other Income (Expense)									(2,124)	(129)	73
Debt Exchange Expense									(9,063)
Gain on Extinguishments of Debt									24,627
Loss on Equity Method Investments										(411)	(813)
Income (Loss) From Equity in Consolidated Subsidiaries									0	0
TOTAL OTHER INCOME (EXPENSE)									(62,594)	11,853	1,191
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(195,201)	(346,752)	31,971
Income Tax Expense									(2,436)	(6,030)	(15,460)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(75,598)	(16,477)	(52,911)	(52,651)	(97,556)	(88,891)	(151,342)	(14,993)	(197,637)	(352,782)	16,511
Income (Loss) From Discontinued Operations, Net of Income Tax									20,922	(8,251)	(59,161)
NET LOSS					(98,037)	(94,676)	(151,803)	(16,517)	(176,715)	(361,033)	(42,650)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations						(1)	949	1,297		2,245	4,039
NET LOSS ATTRIBUTABLE TO REX ENERGY	(67,395)	5,415	(54,594)	(60,141)	(98,037)	(94,675)	(152,752)	(17,814)	(176,715)	(363,278)	(46,689)
Preferred Stock Dividends	(650)	(613)	(1,723)	(2,105)	(2,415)	(2,415)	(2,415)	(2,415)	(5,091)	(9,660)	(2,335)
Effect of Preferred Stock Conversions	668		72,316						72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (67,377)	$ 4,802	$ 15,999	$ (62,246)	$ (100,452)	$ (97,090)	$ (155,167)	$ (20,229)	(108,822)	(372,938)	(49,024)
Eliminations
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries									146,344	309,250	25,250
TOTAL OTHER INCOME (EXPENSE)									146,344	309,250	25,250
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX									146,344	309,250	25,250
NET INCOME (LOSS) FROM CONTINUING OPERATIONS									146,344	309,250	25,250
NET LOSS									146,344	309,250	25,250
NET LOSS ATTRIBUTABLE TO REX ENERGY										309,250	25,250
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									146,344	309,250	25,250
Guarantor Subsidiaries
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales									139,000	138,707	225,511
Other Revenue									17	42	118
TOTAL OPERATING REVENUE									139,017	138,749	225,629
OPERATING EXPENSES
Production and Lease Operating Expense									104,699	93,892	69,547
General and Administrative Expense									17,488	20,849	26,105
(Gain) Loss on Disposal of Assets									(4,121)	(540)	218
Impairment Expense									74,624	282,833	14,269
Exploration Expense									2,177	2,616	6,813
Depreciation, Depletion, Amortization and Accretion									62,849	85,839	65,816
Other Operating Expense									10,754	5,603	312
TOTAL OPERATING EXPENSES									268,470	491,092	183,080
INCOME (LOSS) FROM OPERATIONS									(129,453)	(352,343)	42,549
OTHER INCOME (EXPENSE)
Interest Expense									(1,326)	(248)	(110)
Gain (Loss) on Derivatives, Net									(34,285)	59,242	37,359
Other Income (Expense)									41	(129)	73
Loss on Equity Method Investments										(411)	(813)
Income (Loss) From Equity in Consolidated Subsidiaries									(94)	(429)	(3,131)
TOTAL OTHER INCOME (EXPENSE)									(35,664)	58,025	33,378
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(165,117)	(294,318)	75,927
Income Tax Expense									(2,060)	(5,111)	(38,230)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS									(167,177)	(299,429)	37,697
Income (Loss) From Discontinued Operations, Net of Income Tax									20,887	(45,546)	(63,582)
NET LOSS									(146,290)	(344,975)	(25,885)
NET LOSS ATTRIBUTABLE TO REX ENERGY										(344,975)	(25,885)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(146,290)	(344,975)	(25,885)
Non-Guarantor Subsidiaries
OPERATING EXPENSES
General and Administrative Expense									5		75
Impairment Expense									(5)	411	5,956
Exploration Expense									1	1
Depreciation, Depletion, Amortization and Accretion									25	5	1
TOTAL OPERATING EXPENSES									26	417	6,032
INCOME (LOSS) FROM OPERATIONS									(26)	(417)	(6,032)
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries									94	429	3,131
TOTAL OTHER INCOME (EXPENSE)									94	429	3,131
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX									68	12	(2,901)
Income Tax Expense										(7)	2,917
NET INCOME (LOSS) FROM CONTINUING OPERATIONS									68	5	16
Income (Loss) From Discontinued Operations, Net of Income Tax									(122)	37,965	4,658
NET LOSS									(54)	37,970	4,674
Net Income Attributable to Noncontrolling Interests of Discontinued Operations										2,245	4,039
NET LOSS ATTRIBUTABLE TO REX ENERGY										35,725	635
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(54)	35,725	635
Parent Company
OPERATING EXPENSES
General and Administrative Expense									3,128	5,845	5,737
TOTAL OPERATING EXPENSES									3,128	5,845	5,737
INCOME (LOSS) FROM OPERATIONS									(3,128)	(5,845)	(5,737)
OTHER INCOME (EXPENSE)
Interest Expense									(42,193)	(47,535)	(36,835)
Gain (Loss) on Derivatives, Net									1,770	934	1,517
Other Income (Expense)									(2,165)
Debt Exchange Expense									(9,063)
Gain on Extinguishments of Debt									24,627
Income (Loss) From Equity in Consolidated Subsidiaries									(146,344)	(309,250)	(25,250)
TOTAL OTHER INCOME (EXPENSE)									(173,368)	(355,851)	(60,568)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(176,496)	(361,696)	(66,305)
Income Tax Expense									(376)	(912)	19,853
NET INCOME (LOSS) FROM CONTINUING OPERATIONS									(176,872)	(362,608)	(46,452)
Income (Loss) From Discontinued Operations, Net of Income Tax									157	(670)	(237)
NET LOSS									(176,715)	(363,278)	(46,689)
NET LOSS ATTRIBUTABLE TO REX ENERGY										(363,278)	(46,689)
Preferred Stock Dividends									(5,091)	(9,660)	(2,335)
Effect of Preferred Stock Conversions									72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ (108,822)	$ (372,938)	$ (49,024)

Condensed Consolidating Stat117

Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ (98,037)	$ (94,676)	$ (151,803)	$ (16,517)	$ (176,715)	$ (361,033)	$ (42,650)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss on Equity Method Investments						411	813
Non-Cash Expenses (Income)					24,124	7,649	6,789
Depreciation, Depletion, Amortization and Accretion					67,975	104,822	98,171
Deferred Income Tax Benefit							(25,992)
(Gain) Loss on Derivatives					32,515	(60,176)	(38,876)
Cash Settlements of Derivatives					32,571	55,793	7,281
Dry Hole Expense					905	330	4,064
Gain on Extinguishment of Debt					(24,627)
(Gain) Loss on Sale of Assets					(34,651)	(521)	589
Gain on Sale of Water Solutions						(57,778)
Impairment Expense					78,162	345,775	132,684
Changes in operating assets and liabilities
Accounts Receivable					(6,414)	21,679	(13,620)
Inventory, Prepaid Expenses and Other Assets					906	(568)	(1,359)
Accounts Payable and Accrued Liabilities					2,795	(22,955)	37,274
Other Assets and Liabilities					(1,950)	(2,543)	(2,462)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES					(4,404)	30,885	162,706
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management						58	263
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets					40,884	77,226	546
Proceeds from Joint Venture					19,461	16,611
Acquisitions of Undeveloped Acreage					(6,712)	(28,242)	(169,423)
Capital Expenditures for Development of Oil and Gas Properties and Equipment					(48,982)	(221,099)	(391,422)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES					4,651	(155,446)	(560,036)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit					71,400	229,314	209,895
Repayments of Long-Term Debt and Lines of Credit					(65,230)	(108,335)	(263,152)
Repayments of Loans and Other Notes Payable					(828)	(1,519)	(2,721)
Proceeds from Senior Notes, Net of Discounts and Premiums							325,000
Debt Issuance Costs					(2,983)	(1,414)	(6,824)
Proceeds from the Issuance of Preferred Stock, Net							154,988
Proceeds from the Exercise of Stock Options							515
Purchase of Non-Controlling Interests							(1,840)
Distributions by the Partners of Consolidated Subsidiary						(830)	(1,840)
Dividends Paid on Preferred Stock						(9,660)	(2,335)
NET CASH PROVIDED BY FINANCING ACTIVITIES					2,359	107,556	413,526
NET INCREASE (DECREASE) IN CASH					2,606	(17,005)	16,196
CASH AND CASH EQUIVALENTS – BEGINNING				18,096	1,091	18,096	1,900
CASH AND CASH EQUIVALENTS – ENDING	1,091				3,697	1,091	18,096
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)					146,344	309,250	25,250
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion						(3,963)	(689)
Dry Hole Expense						(5)
Impairment Expense					(78,162)	(347,405)
Changes in operating assets and liabilities
Accounts Receivable						(2,537)	(766)
Accounts Payable and Accrued Liabilities						2,537	766
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES					68,182	(42,123)	24,561
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries					(68,182)	40,959	(28,888)
Capital Expenditures for Development of Oil and Gas Properties and Equipment						1,164	4,328
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES					(68,182)	42,123	(24,560)
CASH FLOWS FROM FINANCING ACTIVITIES
NET INCREASE (DECREASE) IN CASH						0
CASH AND CASH EQUIVALENTS – BEGINNING					0
CASH AND CASH EQUIVALENTS – ENDING	0					0
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)					(146,290)	(344,975)	(25,885)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss on Equity Method Investments						411	813
Non-Cash Expenses (Income)					(212)	(201)	(273)
Depreciation, Depletion, Amortization and Accretion					67,915	105,555	94,643
Deferred Income Tax Benefit							(9,928)
(Gain) Loss on Derivatives					34,285	(59,242)	(37,359)
Cash Settlements of Derivatives					32,571	54,859	5,969
Dry Hole Expense					905	199	3,797
(Gain) Loss on Sale of Assets					(34,697)	(477)	644
Impairment Expense					78,160	345,892	126,662
Changes in operating assets and liabilities
Accounts Receivable					(44,354)	24,240	(11,450)
Inventory, Prepaid Expenses and Other Assets					906	(431)	(1,283)
Accounts Payable and Accrued Liabilities					8,815	(20,008)	23,768
Other Assets and Liabilities					(1,950)	(2,497)	(2,127)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES					(3,946)	103,325	167,992
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries					3,628	96,763	401,412
Proceeds from Joint Venture Acreage Management						58	263
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets					39,904	9,766	254
Proceeds from Joint Venture					19,461	16,611
Acquisitions of Undeveloped Acreage					(6,671)	(27,963)	(168,713)
Capital Expenditures for Development of Oil and Gas Properties and Equipment					(48,943)	(214,450)	(382,889)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES					7,379	(119,215)	(149,673)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable					(828)	(999)	(1,727)
NET CASH PROVIDED BY FINANCING ACTIVITIES					(828)	(999)	(1,727)
NET INCREASE (DECREASE) IN CASH					2,605	(16,889)	16,592
CASH AND CASH EQUIVALENTS – BEGINNING				17,978	1,089	17,978	1,386
CASH AND CASH EQUIVALENTS – ENDING	1,089				3,694	1,089	17,978
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)					(54)	37,970	4,674
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)					3	(334)	278
Depreciation, Depletion, Amortization and Accretion					60	3,230	4,217
Deferred Income Tax Benefit							(1,649)
Dry Hole Expense						136	267
(Gain) Loss on Sale of Assets					46	(44)	(55)
Impairment Expense					2	1,396	6,022
Changes in operating assets and liabilities
Accounts Receivable					(863)	(453)	(6,090)
Inventory, Prepaid Expenses and Other Assets						(142)	(74)
Accounts Payable and Accrued Liabilities						(4,969)	3,488
Other Assets and Liabilities						(73)	(335)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES					(806)	36,717	10,743
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries					(94)	(37,424)	(756)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets					980	560	292
Acquisitions of Undeveloped Acreage					(41)	(279)	(710)
Capital Expenditures for Development of Oil and Gas Properties and Equipment					(39)	(7,813)	(12,861)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES					806	(44,956)	(14,035)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit						35,814	38,895
Repayments of Long-Term Debt and Lines of Credit						(26,335)	(33,152)
Repayments of Loans and Other Notes Payable						(520)	(994)
Debt Issuance Costs						(3)	(8)
Purchase of Non-Controlling Interests							(1,840)
Distributions by the Partners of Consolidated Subsidiary						(830)
NET CASH PROVIDED BY FINANCING ACTIVITIES						8,126	2,901
NET INCREASE (DECREASE) IN CASH					0	(113)	(391)
CASH AND CASH EQUIVALENTS – BEGINNING				113	0	113	504
CASH AND CASH EQUIVALENTS – ENDING	0				0	0	113
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)					(176,715)	(363,278)	(46,689)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)					24,333	8,184	6,784
Deferred Income Tax Benefit							(14,415)
(Gain) Loss on Derivatives					(1,770)	(934)	(1,517)
Cash Settlements of Derivatives						934	1,312
Gain on Extinguishment of Debt					(24,627)
Gain on Sale of Water Solutions						(57,778)
Impairment Expense					78,162	345,892
Changes in operating assets and liabilities
Accounts Receivable					38,803	429	4,686
Inventory, Prepaid Expenses and Other Assets						5	(2)
Accounts Payable and Accrued Liabilities					(6,020)	(515)	9,252
Other Assets and Liabilities						27
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES					(67,834)	(67,034)	(40,589)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries					64,648	(100,298)	(371,768)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets						66,900
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES					64,648	(33,398)	(371,768)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit					71,400	193,500	171,000
Repayments of Long-Term Debt and Lines of Credit					(65,230)	(82,000)	(230,000)
Proceeds from Senior Notes, Net of Discounts and Premiums							325,000
Debt Issuance Costs					(2,983)	(1,411)	(6,816)
Proceeds from the Issuance of Preferred Stock, Net							154,988
Proceeds from the Exercise of Stock Options							515
Dividends Paid on Preferred Stock						(9,660)	(2,335)
NET CASH PROVIDED BY FINANCING ACTIVITIES					3,187	100,429	412,352
NET INCREASE (DECREASE) IN CASH					1	(3)	(5)
CASH AND CASH EQUIVALENTS – BEGINNING				$ 5	2	5	10
CASH AND CASH EQUIVALENTS – ENDING	$ 2				$ 3	$ 2	$ 5

Subsequent Events - Additional

Subsequent Events - Additional Information (Details)	Jan. 11, 2017USD ($)aMMcfeWell	Aug. 18, 2016USD ($)	Dec. 31, 2016USD ($)
Subsequent Event [Line Items]
Proceeds from the transactions		$ 38,500,000	$ 0
Amended to Senior Credit Agreement
Subsequent Event [Line Items]
Line of credit facility, current borrowing capacity			190,000,000
Subsequent Event | Scenario Two | Amended to Senior Credit Agreement | Letter Of Credit
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity	$ 40,000,000
Subsequent Event | Scenario One | Amended to Senior Credit Agreement | Letter of Credit Including Surety Letter of Credit
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity	50,000,000
Subsequent Event | Scenario One | Amended to Senior Credit Agreement | Surety Letter of Credit
Subsequent Event [Line Items]
Line of credit facility, minimum borrowing capacity	10,000,000
Sale of Warrior South Assets
Subsequent Event [Line Items]
Net book value of assets			$ 27,900,000
Sale of Warrior South Assets | Subsequent Event
Subsequent Event [Line Items]
Total consideration for the transaction	29,100,000
Proceeds from the transactions	24,100,000
Amount held in escrow	$ 5,000,000
Number of gross wells | Well	14
Production unit of oil | MMcfe	9
Sale of asset, acres | a	4,100
Rex, MFC, and ABARTA | Sale of Warrior South Assets | Subsequent Event
Subsequent Event [Line Items]
Total consideration for the transaction	$ 50,000,000
Production unit of oil | MMcfe	15
Sale of asset, acres | a	6,200