Rex Energy 10-Q 9 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Aug. 04, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2
Trading Symbol	REXX
Entity Registrant Name	REX ENERGY CORP
Entity Central Index Key	1,397,516
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		9,952,861

Consolidated Balance Sheets (Un

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

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) (Unaudited) - $ / shares	Jun. 30, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Preferred Stock, par value	$ 0.001	$ 0.001
Preferred Stock, shares authorized	100,000	100,000
Preferred Stock, shares issued	3,987	3,987
Preferred Stock, shares outstanding	3,987	3,987
Common Stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common Stock, shares issued	9,952,861	9,787,146
Common Stock, shares outstanding	9,952,861	9,787,146

Consolidated Statements of Oper

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

Consolidated Statement of Chang

Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - 6 months ended Jun. 30, 2017 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at Dec. 31, 2016	$ 10,226	$ 10	$ 1	$ 650,669	$ (640,454)
Balance (in shares) at Dec. 31, 2016		9,787	4
Equity Based Compensation	571			571
Issuance of Common Stock for Debt Extinguishments	467			467
Issuance of Common Stock for Debt Extinguishments (in shares)		84
Issuance of Restricted Stock, Net of Forfeitures (in shares)		82
Effect of Reverse Stock Split	(48)			(48)
Payment of Preferred Dividends in Arrears	(598)				(598)
Net Loss	(6,920)				(6,920)
Balance at Jun. 30, 2017	$ 3,698	$ 10	$ 1	$ 651,659	$ (647,972)
Balance (in shares) at Jun. 30, 2017		9,953	4

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (9,603)	$ (54,594)	$ (6,920)	$ (114,735)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion			30,969	36,345
(Gain) Loss on Derivatives	(10,386)	29,169	(18,766)	25,120
Cash Settlements of Derivatives			(5,525)	30,340
Non-cash Dry Hole Expense			13	870
Equity-based Compensation Expense			571	1,305
Impairment Expense			4,577	39,323
Amortization of net Bond Discount and Deferred Debt Issuance Costs				538
Non-cash Interest Expense related to Debt Restructurings and Exchanges			12,431	8,126
Loss (Gain) on Extinguishments of Debt			3,022	(23,757)
Gain on Sale of Assets			(1,959)	(4,338)
Other Non-cash Expense			41	131
Changes in operating assets and liabilities
Accounts Receivable			7,229	(14,772)
Taxes Receivable			163
Inventory, Prepaid Expenses and Other Assets			52	1,118
Accounts Payable and Accrued Liabilities			(1,484)	10,425
Other Assets and Liabilities			(1,104)	(676)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			23,310	(4,637)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			24,513	190
Proceeds from Joint Venture for Reimbursement of Capital Costs				19,461
Acquisitions of Undeveloped Acreage			(1,783)	(5,900)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(54,004)	(37,738)
NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES			(31,274)	(23,987)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit			171,000	50,400
Repayments of Long-Term Debt and Line of Credit			(145,170)	(15,230)
Repayments of Loans and Other Notes Payable			(319)	(361)
Debt Issuance Costs			(7,791)	(3,838)
Payment of Preferred Dividends in Arrears			(598)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES			17,122	30,971
NET INCREASE IN CASH			9,158	2,347
CASH – BEGINNING			3,697	1,091	$ 1,091
CASH – ENDING	12,855	3,438	12,855	3,438	3,697
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	$ 12,855	$ 3,438	12,855	3,438	$ 3,697
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest			8,494	24,260
Cash Paid (Received) for Income Taxes			(163)	29
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations				991
NON-CASH ACTIVITIES
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets			5,000
Increase (Decrease) in Accrued Liabilities for Capital Expenditures			1,652	(1,688)
Increase in Other Long Term Debt - Capital Lease Equipment Financing			607
Decrease in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Premium / Discount due to Debt to Equity Conversions			(879)	(28,735)
Decrease in Bond Interest Payable due to Debt to Equity Conversions			(12)	(719)
Increase in Common Stock outstanding due to Debt to Equity Conversions			467	$ 5,696
Illinois Basin Operations
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin			$ (1,893)

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	6 Months Ended
	Jun. 30, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent natural gas, natural gas liquid (“NGL”) and condensate company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in natural gas, NLG and condensate properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil, NGLs and natural gas, future impact of financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of oil, NGL and natural gas recovery techniques. Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016. Reverse Stock Split On May 12, 2017, we effected a one-for-ten reverse stock split. As a result of the reverse stock split, each ten shares of our common stock automatically combined into and became one share of our common stock. Any fractional shares which would have otherwise been due as a result of the reverse split were rounded up to the nearest whole share. As a result of the reverse stock split, we reduced the issued number of common shares from 99.0 million to 9.9 million. The reverse stock split automatically and proportionately adjusted, based on the one-for-ten split ratio, all issued and outstanding shares of our common stock, as well as common stock underlying stock options, warrants and other derivative securities outstanding at the time of the effectiveness of the reverse stock split. The exercise price on outstanding equity based-grants proportionately increased, while the number of shares available under our equity-based plans also was proportionately reduced. Share and per share data for the periods presented reflect the effects of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis. Discontinued Operations In 2016, we divested all of our Illinois Basin assets and operations. The sale closed in August 2016, with an effective date of July 1, 2016. As a result of this transaction, the 2016 results of operations of our Illinois Basin operations have been classified as Discontinued Operations in the accompanying Consolidated Statements of Operations for the year ended December 31, 2016. Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 3, Discontinued Operations/Assets Held for Sale

Future Abandonment Cost

Future Abandonment Cost	6 Months Ended
	Jun. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Future Abandonment Cost	2. FUTURE ABANDONMENT COST Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Accretion expense totaled $0.5 million and $1.0 million for the three and six months ended June 30, 2017, respectively, and $0.1 million and $0.4 million for the three and six months ended June 30, 2016, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) June 30, 2017 Beginning Balance at January 1, 2017 $ 9,865 Future Abandonment Obligation Incurred $ 1,062 Future Abandonment Obligation Settled $ (1,051 ) Future Abandonment Obligation Cancelled or Sold $ (262 ) Future Abandonment Obligation Revision of Estimated Obligation $ 57 Future Abandonment Obligation Accretion Expense $ 1,042 Total Future Abandonment Cost 1 $ 10,713 1

Discontinued Operations_Assets

Discontinued Operations/Assets Held For Sale	6 Months Ended
	Jun. 30, 2017
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations/Assets Held For Sale	3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE Illinois Basin Operations On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell agreed to purchase, subject to certain parameters and provisions for adjustment customary for transactions of this type, all of our oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June 2016 and received the additional proceeds of approximately $38.0 million during the third and fourth quarters of 2016. An addendum executed in conjunction with the Agreement allowed for the Company to receive from Campbell potential additional proceeds of up $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ended December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of June 30, 2017, the first three of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds related to those measurement periods. As of June 30, 2017, we have the potential to receive up to $7.2 million of additional proceeds, during the eight remaining measurement periods. For additional information, see Note 8, Derivative Instruments and Fair Value Measurements Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays). Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day. The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations. As of June 30, 2017 and December 31 2016, we had no remaining assets or liabilities related to our former Illinois Basin operations. The results of operations of our Illinois Basin operations are reported as Discontinued Operations for the three and six months ended June 30, 2016, in our Consolidated Statements of Operations. Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. The sale of our Illinois assets and operations does not include any of our derivative contracts or positions related to our Illinois Basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the three and six month periods ended June 30, 2017 and 2016. For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2017 2016 2017 2016 Revenues: Oil Sales $ — $ 6,393 $ — $ 11,213 Total Operating Revenue — 6,393 — 11,213 Costs and Expenses: Production and Lease Operating Expense — 5,029 — 10,725 General and Administrative Expense — 659 — 1,437 Gain on Disposal of Assets — (2 ) — (43 ) Impairment Expense — — — 3,543 Exploration Expense — 85 — 143 Depreciation, Depletion, Amortization and Accretion — 2,186 — 5,083 Interest Expense — 1 — 3 Other Income — (2 ) — (3 ) Total Costs and Expenses — 7,956 — 20,888 Loss From Discontinued Operations, Before Income Taxes — (1,563 ) — (9,675 ) Income Tax Expense — (120 ) — 502 Loss From Discontinued Operations, Net of Taxes $ — $ (1,683 ) $ — $ (9,173 ) Production: Crude Oil (Bbls) — 150,980 — 308,720

Business and Oil and Gas Proper

Business and Oil and Gas Property Acquisitions and Dispositions	6 Months Ended
	Jun. 30, 2017
Business Combinations [Abstract]
Business and Oil and Gas Property Dispositions	4. BUSINESS AND OIL AND GAS PROPERTY DISPOSITIONS Benefit Street Partners, LLC On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of June 30, 2017. BSP has paid approximately $103.0 million for its interest in elected wells as of June 30, 2017. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of June 30, 2017, 34 of the 45 committed wells were in line and producing, four were completed waiting to go in line, and seven wells were drilled and awaiting completion. The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized. Diversified Oil & Gas, LLC On May 20, 2016, we entered into a Purchase and Sale Agreement (the “PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $0.1 million. Included in the sale were approximately 300 wells, pipelines and support equipment . Gain on Disposal of Assets Illinois Basin Operations As described in Note 3, Discontinued Operations/Assets Held for Sale Sale of Warrior South Assets On January 11, 2017, we, together with MFC Drilling, Inc. (“MFC”), and ABARTA Oil & Gas Co., Inc. (“ABARTA”) (together, the “Sellers”) sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation (“Antero”). These interests comprised our Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to Rex, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017. Approximately $5.0 million of the total proceeds due to us will be held in escrow and will be released in January 2018, net of post-closing adjustments. The proceeds held in escrow are classified as accounts receivable on our Consolidated Balance Sheet as of June 30, 2017. The sale of assets resulted in a gain on disposal of assets of approximately $1.8 million in January 2017. This gain includes the additional proceeds held in escrow, which we anticipate receiving in January 2018. The sale of assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to us, and approximately 6,200 gross acres, with 4,100 acres net to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down our revolving line of credit and for general corporate purposes.

Recently Issued Accounting Pron

Recently Issued Accounting Pronouncements	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Recently Issued Accounting Pronouncements	5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In May 2014, the Financial Accounting Standards Board (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 February 2016, the FASB issued ASU 2016-02, Leases • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

Concentrations of Credit Risk

Concentrations of Credit Risk	6 Months Ended
	Jun. 30, 2017
Risks And Uncertainties [Abstract]
Concentrations of Credit Risk	6. CONCENTRATIONS OF CREDIT RISK By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions (see Note 7, Long-Term Debt Derivative Instruments and Fair Value Measurements We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the six months ended June 30, 2017, approximately 95.3% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 50.7% of commodity sales. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of condensate and gas sales as well as the quantity of purchasers.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	7. LONG-TERM DEBT Term Loan On April 28, 2017 (the “Effective Date”), we entered into a term loan agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent (in such capacity, the “Administrative Agent”), AGES, as collateral agent (in such capacity, the “Collateral Agent”), Macquarie Bank Limited, as issuing bank (in such capacity, the “Issuing Bank”), and the lenders from time to time party thereto. The Term Loan replaced our existing amended and restated senior secured revolving credit agreement (the “Existing Credit Agreement”). The Term Loan provides for a $143,500,000 secured term loan facility (the “Term Facility”) and a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit sub-facility (the “Letter of Credit Sub-facility”). The proceeds of the initial loans under the Term Loan were used for refinancing of loans under the Existing Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility may be used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes. The maximum commitments of the lenders under the Term Loan are currently limited to $300,000,000. Amounts borrowed and repaid may not be re-borrowed. The maturity date for the loans under the Term Facility and the loans drawn under the Delayed Draw Term Facility is the earlier of (a) April 28, 2021 and (b) the date that is six months prior to the maturity of the Company’s 1.00/8.00% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) unless less than $25,000,000 Second Lien Notes are then outstanding and no Event of Default (as defined in the Term Loan) exists on such date. The commitments under the Delayed Draw Term Facility expire if not drawn prior to the earlier of (a) April 28, 2018 (which date may be extended for one year with lender consent) and (b) the date upon which the Borrower terminates such commitments. As of June 30, 2017, we had $143.5 million borrowings outstanding and approximately $46.3 million in outstanding undrawn letters of credit. We incurred approximately $3.5 million in debt issuance costs and $4.3 million in original issue discount (“OID”) related to the initial Term Loan borrowing. From April 28, 2017 through June 30, 2017, we amortized $0.2 million of debt issuance costs and $0.2 million of OID. The amortization of debt issuance costs and OID are reported as Interest Expense Borrowings under the Term Loan bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. The “Adjusted LIBO Rate” is equal to the product of the three month LIBOR rate multiplied by the statutory reserve rate. Upon the occurrence and continuance of an Event of Default all outstanding loans shall bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable on the last Business Day of each March, June, September and December. Under the Term Loan the Company will pay a 3.5% commitment fee on any unused portion of the Delayed Draw Term Facility. The Term Loan requires us to prepay the loans with 100% of the net cash proceeds received from certain asset sales, swap terminations, incurrences of borrowed money indebtedness, casualty events and equity issuances, subject to certain exceptions and specified reinvestment rights. Prepayments based on 75% of excess cash flow are required until no more than $287,950,000 in Second Lien Notes remain outstanding, at which time, prepayments based on 50% of excess cash flow will be required. Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan are subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and 1 day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount. The Term Loan contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividend payments, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions. The Term Loan also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after December 31, 2017, the PDP Coverage Ratio (as defined in the Term Loan) will not be less than 1.65 to 1.00; (2) as of the last day of any fiscal quarter ending on or after March 31, 2017, the ratio of Net Senior Secured Debt (as defined in the Term Loan) as of such date to EBITDAX (as defined in the Term Loan) for the period of four fiscal quarters then ending on such day will not be greater than 3.25 to 1.00 (provided that EBITDAX for the four fiscal quarters ending on (i) March 31, 2017 shall be EBITDAX for the fiscal quarter then ending multiplied by four and (ii) June 30, 2017 shall be EBITDAX for the two fiscal quarters then ending multiplied by two); and (3) as of the last day of any fiscal quarter ending on or after September 30, 2017 s of June 30, 2017, our Net Senior Secured Debt to EBITDAX Ratio was 2.33 to 1.00 Our obligations under the Credit Agreement may be accelerated upon the occurrence of an Event of Default (as such term is defined in the Term Loan). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the Term Loan). Obligations under the Term Loan are secured by mortgages on our oil and gas properties. In connection with the Term Loan, we, including our wholly owned subsidiaries, Rex Energy I, LLC, Rex Energy Operating Corp., PennTex Resources Illinois, Inc., Rex Energy IV, LLC, and R.E. Gas Development, LLC (collectively, the “Guarantors” and together with us, the “Grantors”), entered into an amended and restated guaranty and collateral agreement, dated as of April 28, 2017, in favor of the Collateral Agent for the lenders from time to time party to the Term Loan, the secured swap parties and the Issuing Bank (the “Guaranty and Collateral Agreement”). Pursuant to the Guaranty and Collateral Agreement, each of the Guarantors, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Term Loan. In addition, each Grantor granted, as security for the prompt and complete payment and performance when due of such Grantor’s obligations, a security interest in substantially all of its assets, including equity interests in other Guarantors, as applicable. Senior Secured Line of Credit On April 28, 2017, we terminated our Senior Secured Line of Credit (the “Senior Credit Facility”) with Royal Bank of Canada, as Administrative Agent and the lenders from time to time parties thereto. We used the initial term draw borrowing under the Term Loan to repay and retire in full the Senior Credit Facility. In conjunction with the retirement of the Senior Credit Facility, we wrote off $3.4 million of associated unamortized debt issuance costs, included in Loss on Extinguishments of Debt Senior Notes On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. See Note 9, Income Taxes In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of New Notes and (ii) 8.4 million Shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept Shares. In addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending October 1, 2020. In connection with the Exchange, we incurred approximately $9.1 million in third-party debt issuance costs during the year ended December 31, 2016. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations. Following the completion of the Exchange, we entered into debt-for equity exchanges during the remainder of 2016, with certain holders of our Existing Notes, as well as holders of our New Notes, in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of $27.7 million of our remaining Existing Notes and $45.7 million of our outstanding New Notes, in exchange for the issuance of a total of approximately 22.7 million shares of unrestricted common stock during the year ended December 31, 2016. In the six months ended June 30, 2017, we completed debt-for equity exchanges with certain holders of our Existing Notes. These exchanges resulted in the retirement of approximately $0.9 million of our remaining Existing Notes, in exchange for approximately 0.1 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the Company for the six months ended June 30, 2017 of approximately $0.4 million, presented as Gain on Extinguishments of Debt in our Consolidated Statements of Operations. We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Existing Notes and the New Notes from the holders. Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges on our Consolidated Balance Sheets. The Senior Notes are governed by indentures (the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00. As of June 30, 2017, our Fixed Charge Coverage Ratio was 1.05 to 1.00. We expect our Fixed Charge Coverage Ratio to improve based on our projections of decreased interest expense related to the New Notes, increased production and improved price realizations. As of June 30, 2017, we were limited to incurring approximately $75.2 million of additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual Trustees or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. As of June 30, 2017 and December 31, 2016, we had recorded on our Consolidated Balance Sheets approximately $11.2 million and $3.6 million, respectively, of net premium related to the Senior Notes. The amortization of our net premium during the three and six months ended June 30, 2017, which follows the effective interest method, was approximately $3.8 million and $7.6 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year. June 30, 2017 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 143,500 $ (4,072 ) $ (3,265 ) $ - $ 136,163 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ 23 $ (92 ) $ - $ 7,264 6.25% Senior Notes due 2022 5,363 - (73 ) - 5,290 1% / 8% Second Lien Senior Notes due 2020 587,606 (11,250 ) 26,915 32,995 636,266 $ 600,302 $ (11,227 ) $ 26,750 $ 32,995 $ 648,820 Other Long-Term Debt Long-Term Capital Leases - Equipment Financing Due March, 2021 $ 699 Due June, 2021 2,045 Due September, 2021 1,717 Total Capital Lease Obligations $ 4,461 Less: Current Portion of Capital Leases (834 ) $ 3,627 The weighted average interest rate on borrowed balances under the Term Loan for the three and six months ended June 30, 2017 was approximately 10.1% and 9.99%, respectively. The weighted average interest rate on the Senior Secured Line of Credit for the three and six months ended June 30, 2017 was approximately 4.9% and 4.1%, respectively. The average interest rate on our capital leases for the three and six months ended June 30, 2017 was approximately 17.2% and 14.4%, respectively. December 31, 2016 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Senior Secured Line of Credit, Net Revolving Senior Credit Facility $ 117,670 $ - $ (3,885 ) $ - $ 113,785 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,573 $ 26 $ (107 ) $ - $ 7,492 6.25% Senior Notes due 2022 5,648 - (82 ) - 5,566 1% / 8% Second Lien Senior Notes due 2020 587,956 (3,627 ) 8,098 32,676 625,103 $ 601,177 $ (3,601 ) $ 7,909 $ 32,676 $ 638,161 Other Long-Term Debt Long-Term Capital Leases and Other Notes Payable- Equipment Financing Due March, 2021 $ 760 Due June, 2021 2,225 Due September, 2021 1,174 Total Capital Lease Obligations $ 4,159 Other Notes Payable 14 Total Capital Lease and Note Payable Obligations $ 4,173 Less: Current Portion of Capital Leases and Other Notes Payable (764 ) $ 3,409 The following is the principal maturity schedule for debt outstanding as of June 30, 2017: 2017 $ 399 2018 908 2019 1,076 2020 739,715 2021 802 Thereafter 5,363 Total (a) $ 748,263 (a) Excludes $15.3 million of net unamortized premium/discount, $23.5 million of net unamortized debt issuance costs, and $33.0 million of unamortized deferred gain on debt restructurings.

Derivative Instruments And Fair

Derivative Instruments And Fair Value Measurements	6 Months Ended
	Jun. 30, 2017
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Derivative Instruments And Fair Value Measurements	8. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of June 30, 2017 and December 31, 2016, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net. We enter into the majority of our derivative arrangements with two counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on 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 Expense. We paid net cash settlements of $2.1 As of June 30, 2017, we had approximately 75.0% of our annualized condensate production hedged through the remainder of 2017, over 90.0% and 60.0% of our annualized natural gas production hedged through the remainder of 2017 and 2018, respectively, and over 70.0% and 50.0% of our annualized NGL production hedged through the remainder of 2017 and 2018, respectively. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our natural gas, condensate and NGL production. Contingent Consideration – Sale of Illinois Basin Operations In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets as defined in the contract are achieved at specified future dates. See Note 3, Discontinued Operations / Assets Held for Sale Interest Rate Derivatives We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of June 30, 2017, and December 31, 2016, we had $143.5 million and $117.7 million outstanding under our Term Loan and our Senior Credit Facility, respectively, which is subject to variable rates of interest and $600.3 million and $601.2 million, respectively, of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt As of June 30, 2017 and December 31, 2016, we did not have any interest rate derivatives outstanding. We utilize the mark-to-market accounting method to account for interest rate swap and swaptions. When applicable, we recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. Derivative Instruments from Continuing Operations The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016: For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2017 2016 2017 2016 Oil $ 791 $ (2,494 ) $ 1,934 $ (2,169 ) Natural Gas 6,132 (18,666 ) 6,072 (13,302 ) NGLs 3,938 (8,093 ) 12,653 (9,714 ) Refined Products — 84 — 65 Contingent Consideration (475 ) — (1,893 ) — Gain (Loss) on Derivatives, Net $ 10,386 $ (29,169 ) $ 18,766 $ (25,120 ) Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $3.9 million and approximately $28.2 million at June 30, 2017 and December 31, 2016, respectively. Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2017 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2017 - Swaps 30,000 Bbls $ — $ — $ — $ 54.00 $ 175 2017 - Three-Way Collars 78,000 Bbls 39.62 49.23 61.35 — 228 2018 - Swaps 60,000 Bbls — — — 54.00 350 2018 - Collars 18,000 Bbls — 53.00 60.00 — 113 2018 - Three-Way Collars 60,000 Bbls 43.00 52.00 62.30 — 211 2019 - Swaps 31,500 Bbls — — — 51.00 21 2019 - Three-Way Collars 21,000 Bbls 37.50 47.50 59.00 — 6 2020 - Swaps 24,000 Bbls — — — 51.00 21 2020 - Three-Way Collars 3,000 Bbls 37.50 47.50 59.00 — 1 2021 - Swaps 6,000 Bbls — — — 51.00 5 331,500 Bbls $ 1,131 Natural Gas 2017 - Swaps 5,990,000 Mcf — — — 3.12 $ 234 2017 - Swaptions 1,200,000 Mcf — — — 3.33 269 2017 - Cap Swaps 1,800,000 Mcf 2.25 — — 2.70 (703 ) 2017 - Collars 1,100,000 Mcf — 2.62 3.25 — (48 ) 2017 - Three-Way Collars 8,490,000 Mcf 2.29 2.98 3.86 — 669 2017 - Calls 1,500,000 Mcf — — 3.64 — (154 ) 2017 - Basis Swaps - Dominion South 5,635,000 Mcf — — — (0.80 ) (688 ) 2017 - Basis Swaps - Texas Gas 7,360,000 Mcf — — — (0.13 ) 4 2018 - Swaps 15,335,000 Mcf — — — 3.10 1,321 2018 - Swaptions — Mcf — — — — (143 ) 2018 - Three-Way Collars 8,775,000 Mcf 2.30 2.89 3.58 — 228 2018 - Calls 5,810,000 Mcf — — 3.97 — (527 ) 2018 - Collars 450,000 Mcf — 3.20 3.65 — 38 2018 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.83 ) (3,029 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf (0.13 ) 8 2019 - Swaps 6,350,000 Mcf — — — 2.91 26 2019 - Three-Way Collars 5,000,000 Mcf 2.35 2.85 3.60 — 46 2019 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.84 ) (3,256 ) 2020 - Swaps 3,660,000 Mcf — — — 2.90 (29 ) 2020 - Three-Way Collars 1,810,000 Mcf 2.35 2.85 3.60 — 46 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.84 ) (1,722 ) 2021 - Swaps 900,000 Mcf — — — 2.90 (7 ) 2021 - Three-Way Collars 300,000 Mcf 2.35 2.85 3.60 — 12 2021 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 143,535,000 Mcf $ (9,509 ) NGLs 2017 - C3+ NGL Swaps 841,000 Bbls — — — 29.70 $ (779 ) 2017 - Ethane Swaps 450,000 Bbls — — — 10.50 (54 ) 2018 - C3+ NGL Swaps 1,110,000 Bbls — — — 31.50 3,102 2018 - Ethane Swaps 750,000 Bbls — — — 13.02 539 2019 - C3+ NGL Swaps 353,250 Bbls — — — 26.04 200 2019 - C5 Collars 113,040 Bbls — 44.94 55.02 — 5 2019 - Ethane Swaps 480,000 Bbls — — — 13.02 130 2020 - C3+ NGL Swaps 135,000 Bbls — — — 24.78 256 2020 - C5 Collars 28,260 Bbls — 44.94 55.02 — 1 2020 - Ethane Swaps 48,000 Bbls — — — 13.44 (3 ) 2021 - C3+ NGL Swap 30,000 Bbls — — — 24.78 62 2021 - Ethane Swaps 9,000 Bbls — — — 13.44 (1 ) 4,347,550 Bbls $ 3,458 The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 is summarized below: June 30, December 31, ($ in Thousands) 2017 2016 Short-Term Derivative Assets: Crude Oil—Three-Way Collars $ 333 $ — Crude Oil—Swaps 350 — Crude Oil—Collars 113 — NGL—Swaps 3,210 — Natural Gas—Swaps 1,292 206 Natural Gas—Cap Swaps — 61 Natural Gas—Collars 63 — Natural Gas—Basis Swaps 211 232 Natural Gas—Three-Way Collars 1,141 151 Natural Gas—Swaption 269 — Contingent Consideration - Sale of Illinois Basin 335 1,223 Total Short-Term Derivative Assets $ 7,317 $ 1,873 Long-Term Derivative Assets: Crude Oil—Three-Way Collars $ 113 $ — Crude Oil—Swaps 222 — NGL—Swaps 2,553 — NGL—Collars 14 — Natural Gas—Swaps 760 206 Natural Gas—Basis Swaps 53 293 Natural Gas—Three-Way Collars 396 — Contingent Consideration - Sale of Illinois Basin 709 1,713 Total Long-Term Derivative Assets $ 4,820 $ 2,212 Total Derivative Assets $ 12,137 $ 4,085 Short-Term Derivative Liabilities: Crude Oil—Collars $ — $ (86 ) Crude Oil—Deferred Put Spread — (9 ) Crude Oil—Three-Way Collars — (132 ) Crude Oil—Swaps — (220 ) NGL—Swaps (2,211 ) (9,895 ) Natural Gas—Three-Way Collars (368 ) (2,397 ) Natural Gas—Cap Swaps (703 ) (3,364 ) Natural Gas—Collars (73 ) (873 ) Natural Gas—Basis Swaps (2,291 ) (640 ) Natural Gas—Call (418 ) (1,478 ) Natural Gas—Swaption (71 ) (1,258 ) Natural Gas—Swaps (428 ) (4,673 ) Total Short - Term Derivative Liabilities $ (6,563 ) $ (25,025 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars $ — $ (58 ) Crude Oil—Swaps — (146 ) NGL—Swaps (100 ) (2,200 ) NGL—Collars (8 ) — Natural Gas—Swaps (79 ) (1,004 ) Natural Gas—Swaption (72 ) (167 ) Natural Gas—Basis Swaps (8,760 ) (1,260 ) Natural Gas—Collars — (115 ) Natural Gas—Call (263 ) (491 ) Natural Gas—Three-Way Collars (168 ) (1,786 ) Total Long-Term Derivative Liabilities $ (9,450 ) $ (7,227 ) Total Derivative Liabilities $ (16,013 ) $ (32,252 ) Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 2 fair value measurements are comprised of our derivative contracts and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of June 30, 2017 and December 31, 2016, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. We had no Level 3 commodity derivative contracts outstanding as of June 30, 2017 or December 31, 2016. The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three and six months ended June 30, 2017 and for the year ended December 31, 2016 there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at June 30, 2017 ($ in Thousands) Total Carrying Value as of June 30, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (3,876 ) $ — $ (3,876 ) $ — Fair Value Measurements at December 31, 2016 ($ in Thousands) Total Carrying Value as of December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (28,167 ) $ — $ (28,167 ) $ — Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations. The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair values attributable to our oil derivatives as of June 30, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of June 30, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of June 30, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments. Future Abandonment Cost We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: June 30, 2017 December 31, 2016 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net $ 648,820 $ 288,156 $ 638,161 $ 147,605 Secured Line of Credit, Net of Issuance Costs — — 113,785 113,785 Term Loans, Net 136,163 136,163 — — Capital Leases and Other Obligations 4,461 3,074 4,173 3,234 Total $ 789,444 $ 427,393 $ 756,119 $ 264,624 The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 1 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy. The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. Other Fair Value Measurements During the six months ended June 30, 2017 and 2016, we recorded other than temporary impairments of $4.6 million and $35.8 million, respectively, related to proved and unproved properties. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 3 within the fair value hierarchy. For additional information on our impairment expense, see Note 15, Impairment Expense

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	9. INCOME TAXES We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. Income tax included in continuing operations was as follows: Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2017 2016 2017 2016 Income Tax Benefit (Expense) $ — $ 393 $ — $ (2,321 ) Effective Tax Rate 0.0 % 0.7 % 0.0 % -2.2 % Management estimates the annual effective income tax rate quarterly, based on current annual forecasted results. Items unrelated to current year ordinary income are recognized entirely in the period identified as a discrete item of tax. The quarterly income tax provision is comprised of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items. The Company accounts for the tax effects of discontinued operations as a discrete item and therefore recognizes the full tax effects of discontinued operations in the same period that the pretax income or loss from discontinued operations is recognized. This approach results in a tax benefit being recorded in continuing operations to offset the tax charge on the gain recorded in discontinued operations, when a full valuation allowance exists on the deferred tax attributes of the Company’s entire operations. For the six months ended June 30, 2017, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of maintaining a full valuation allowance against our deferred tax assets. For the six months ended June 30, 2016 the estimated annual effective tax rate applied to ordinary losses from continuing operations was -2.2%. The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets coupled with recognizing tax benefits in continuing operations for the effect of taxable income generated by our discontinued operations. To a lesser extent, the annual effective rate is also influenced by alternative minimum tax with no corresponding deferred tax benefit due to the full valuation allowance, and state taxes in certain tax paying jurisdictions. The Company’s alternative minimum tax due for 2016 is driven primarily by cancellation of debt income of $543.2 million related to the Senior Note exchanges discussed in Note 7, Long-Term Debt Income tax payments made during the six months ended June 30, 2017 were $2.0 million, and payments made during the six months ended June 30, 2016 were negligible. Tax refunds received during the six months ended June 30, 2017 were approximately $0.2 million, and refunds received during the six months ended June 30, 2016 were negligible.

Capital Stock

Capital Stock	6 Months Ended
	Jun. 30, 2017
Equity [Abstract]
Capital Stock	10. CAPITAL STOCK Reverse Stock Split As discussed in Note 1, Basis of Presentation and Principles of Consolidation references to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis. Common Stock On May 27, 2016, the Company’s common shareholders approved an increase in the number of authorized shares from 100,000,000 to 200,000,000 common shares. On May 5, 2017, the Company’s common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017. As of June 30, 2017, we have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2017 and December 31, 2016, shares of common stock issued and outstanding totaled 9,952,861 and 9,787,146, respectively. During the six months ended June 30, 2017, we issued approximately 0.1 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes. See Note 7, Long-Term Debt Preferred Stock As of both June 30, 2017 and December 31, 2016, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), issued and outstanding totaled 3,987. During the six months ended June 30, 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 0.9 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. See Note 13, Earnings Per Common Share The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on February 15, May 15, August 15 and November 15 of each year. We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. In May 2017, we paid a cash dividend of $150.00 per share for the period of November 15, 2015 to February 15, 2016 in the aggregate amount of $0.6 million. As of June 30, 2017, accumulated dividends in arrears totaled $3.0 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulation of unpaid dividends during the current reporting period is included in our Net Income (Loss) in the determination of Net Income (Loss) Attributable to Common Shareholders and related earnings per share calculations. If dividends are in arrears and unpaid for six or more quarterly periods (whether or not consecutive), the holders of the shares of Series A Preferred Stock will have the right to elect two additional directors to serve on our board of directors.

Employee Benefit and Equity Pla

Employee Benefit and Equity Plans	6 Months Ended
	Jun. 30, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefit and Equity Plans	11. EMPLOYEE BENEFIT AND EQUITY PLANS Equity Plans We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities. Stock Options During the six months ended June 30, 2017, no new options to purchase shares of our common stock were granted. During the six months ended June 30, 2016, we issued 88,892 options to purchase shares of our common stock to 34 employees. Stock-based compensation expense from continuing operations relating to stock options outstanding for the three and six months ended June 30, 2017 was $0.1 million and $0.2 million, respectively. Stock-based compensation expense from continuing operations relating to stock options outstanding for each of the three and six months ended June 30, 2016 was $0.1 million. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. There were no stock options exercised during the six months ended June 30, 2017. There was no tax benefit related to stock option exercises for each of the six-month periods ended June 30, 2017 and 2016. A summary of the status of our issued and outstanding stock options as of June 30, 2017 is as follows: Outstanding Exercisable Exercise Price Number Outstanding at June 30, 2017 Weighted-Average Exercise Price Number Exercisable at June 30, 2017 Weighted-Average Exercise Price 9.70 2,750 $ 9.70 918 $ 9.70 16.90 75,352 $ 16.90 25,125 $ 16.90 40.50 4,000 $ 40.50 — $ 40.50 49.00 4,000 $ 49.00 666 $ 49.00 50.40 3,070 $ 50.40 3,070 $ 50.40 95.00 5,000 $ 95.00 5,000 $ 95.00 99.90 12,959 $ 99.90 12,959 $ 99.90 104.20 2,217 $ 104.20 2,217 $ 104.20 223.40 3,000 $ 223.40 3,000 $ 223.40 112,348 $ 39.91 52,955 $ 62.16 The weighted average remaining contractual term for options outstanding at June 30, 2017 was 4.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at June 30, 2017 was 3.2 years and there was no aggregate intrinsic value. As of June 30, 2017, unrecognized compensation expense related to stock options was $0.2 million. Restricted Stock Awards During the six-month period ended June 30, 2017, the Compensation Committee approved the issuance of an aggregate of 101,237 shares of restricted common stock to 28 employees. During the six-month period ended June 30, 2016, the Compensation Committee approved the issuance of an aggregate of 42,883 shares of restricted stock to 25 employees. Certain of our outstanding restricted stock awards granted in 2015 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group over a three-year period. The weighted average fair value of the TSR awards granted as of December 31, 2015 was $2.56 per share. There have been no TSR awards granted subsequent to December 31, 2015. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions: Year Ended December 31, 2015 Expected Dividend Yield 0.0 % Risk-Free Interest Rate 1.0 % Expected Volatility – Rex Energy 58.6 % Expected Volatility – Peer Group 29.8%-85.0% Market Index 35.6 % Expected Life Three Years During the six months ended June 30, 2017, 17,952 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.1 million for the quarter. Compensation expense from restricted stock awards associated with our continuing operations was negligible and $0.4 million for the three and six months ended June 30, 2017, respectively, and $1.1 million and $0.9 million for the three and six months ended June 30, 2016, respectively. During the first quarter of 2016, 23,557 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.2 million for the quarter. As of June 30, 2017, total unrecognized compensation cost related to restricted common stock grants was approximately $1.1 million, which will be recognized over a weighted average period of 1.6 years. A summary of the restricted stock activity for the six months ended June 30, 2017 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2016 242,824 $ 26.34 Awards 101,237 5.18 Forfeitures (19,185 ) 86.78 Vested (39,278 ) 22.18 Restricted stock awards, as of June 30, 2017 $ 285,598 $ 15.35

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	12. COMMITMENTS AND CONTINGENCIES Legal Reserves We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations. The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred. For the quarter ended June 30, 2017, therewere no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, as supplemented by our Periodic Report on Form 10-Q for the period ended March 31, 2017. Environmental Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of June 30, 2017, we know of no significant probable or possible environmental contingent liabilities. Letters of Credit As of June 30, 2017, we have posted $46.3 million in various letters of credit to secure our drilling and related operations. Lease Commitments As of June 30, 2017, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2017, was approximately $0.2 million and $0.5 million, respectively, and $0.3 million and $0.6 million for the three and six months ended June 30, 2016, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2017 $ 505 2018 565 2019 563 2020 422 2021 — Thereafter — Total $ 2,055 Capacity Reservation We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $9.1 million in 2017, $15.9 million in 2018, $15.9 million in 2019, $15.9 million in 2020, $15.9 million in 2021 and $78.3 million thereafter, assuming our average net revenue interest in the region of approximately 51%. Charges incurred for unutilized processing capacity with MarkWest during the three and six months ended June 30, 2017 were $1.7 million and $3.3 million, respectively, and $0.8 million and $1.4 million for the three and six months ended June 30, 2016, respectively. Operational Commitments We have contracted drilling rig services for one rig to support our Appalachian Basin operations. The minimum cost to retain the rig would require gross payments of approximately $1.4 million in 2017 and $1.8 million in 2018, which would be partially offset by other working interest owners, which vary from well to well. Natural Gas Gathering, Processing and Sales Agreements During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our natural gas, NGLs and condensate. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $391.5 million through 2029. For the three and six months ended June 30, 2017, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $26.4 million and $52.7 million, respectively, and $21.8 million and $43.3 million for the three and six months ended June 30, 2016, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. During the three and six months ended June 30, 2017, we incurred fees related to unutilized capacity commitments of approximately $0.7 million and $1.4 million, respectively, and $0.7 million and $1.0 million for the three and six months ended June 30, 2016, respectively. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) 2017 $ 22,281 2018 46,241 2019 46,408 2020 45,123 2021 42,204 Thereafter 464,028 Total $ 666,285 Pennsylvania Impact Fee In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates: <$2.25(a) $2.26 - $2.99(a) $3.00 - $4.99(a) $5.00 - $5.99(a) >$5.99(a) Year One $ 40,200 $ 45,300 $ 50,300 $ 55,300 $ 60,400 Year Two $ 30,200 $ 35,200 $ 40,200 $ 45,300 $ 55,300 Year Three $ 25,200 $ 30,200 $ 30,200 $ 40,200 $ 50,300 Year 4 – 10 $ 10,100 $ 15,100 $ 20,100 $ 20,100 $ 20,100 Year 11 – 15 $ 5,000 $ 5,000 $ 10,100 $ 10,100 $ 10,100 (a ) All fees owed are due on April 1 of each year. For the three and six months ended June 30, 2017, we recorded expense of approximately $0.8 million and $1.6 million, respectively and $0.8 million and $1.3 million for the three and six months ended June 30, 2016, respectively.

Earnings Per Common Share

Earnings Per Common Share	6 Months Ended
	Jun. 30, 2017
Earnings Per Share [Abstract]
Earnings Per Common Share	13. EARNINGS PER COMMON SHARE Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the three and six months ended June 30, 2017, we excluded stock options to purchase 112,348 shares of our common stock, due to exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three and six months ended June 30, 2016, we excluded stock options to purchase 130,447 shares of our common stock, due to our Net Loss from Continuing Operations. For the three and six month periods ended June 30, 2017 and 2016, we excluded performance-based restricted stock of 43,124 shares and 71,715 shares, respectively, due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 11, Employee Benefit and Equity Plans (in thousands, except per share amounts) Three Months Ended June 30, Six Months Ended June 30, Numerator: 2017 2016 2017 2016 Net Loss From Continuing Operations $ (9,603 ) $ (52,911 ) $ (6,920 ) $ (105,562 ) Net Loss From Discontinued Operations — (1,683 ) — (9,173 ) Less: Preferred Stock Dividends (598 ) (1,723 ) (1,196 ) (3,828 ) Effect of Preferred Stock Conversions — 72,316 — 72,316 Net Income (Loss) Attributable to Common Shareholders $ (10,201 ) $ 15,999 $ (8,116 ) $ (46,247 ) Denominator: Weighted Average Common Shares Outstanding - Basic 9,881 7,180 9,825 6,404 Effect of Dilutive Securities: Employee Stock Options — — — — Employee Performance-Based Restricted Stock Awards — — — — Effect of Assumed Conversions of Preferred Stock — — — — Weighted Average Common Shares Outstanding - Diluted 9,881 7,180 9,825 6,404 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Income (Loss) From Continuing Operations $ (1.03 ) $ 2.45 $ (0.83 ) $ (5.79 ) — Net Loss From Discontinued Operations — (0.23 ) — (1.43 ) — Net Income (Loss) Attributable to Common Shareholders $ (1.03 ) $ 2.22 $ (0.83 ) $ (7.22 ) Diluted — Net Income (Loss) From Discontinued Operations $ (1.03 ) $ 2.45 $ (0.83 ) $ (5.79 ) — Net Loss From Discontinued Operations — (0.23 ) — (1.43 ) — Net Income (Loss) Attributable to Common Shareholders $ (1.03 ) $ 2.22 $ (0.83 ) $ (7.22 )

Equity Method Investments

Equity Method Investments	6 Months Ended
	Jun. 30, 2017
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	14. EQUITY METHOD INVESTMENTS RW Gathering, LLC We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our natural gas operations. We did not make any capital contributions to RW Gathering during the first six months of 2017 and 2016. RW Gathering recorded net losses from continuing operations of $0.5 million and $1.0 million during the three and six months ended June 30, 2017, respectively, as compared to losses of $0.5 million and $1.0 million for the three and six months ended June 30, 2016, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Historically, we recorded our share of the net losses on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued applying the equity method of accounting for our share of net losses due to our investment being reduced to zero. During the three and six months ended June 30, 2017 and 2016, we incurred approximately $0.1 million and $0.3 million, respectively, in compression expenses each year that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of June 30, 2017 and December 31, 2016, there were no receivables or payables due between RW Gathering and us.

Impairment Expense

Impairment Expense	6 Months Ended
	Jun. 30, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment Expense	15. IMPAIRMENT EXPENSE For the three and six months ended June 30, 2017, impairment expenses for continuing operations incurred were approximately $3.0 million and $4.6 million, respectively, and impairment expenses incurred for the three and six months ended June 30, 2016, were approximately $25.1 million and $35.8 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the six months ended June 30, 2017, included approximately $3.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Impairments of unconventional proved properties in our Butler County operations totaled approximately $0.8 million during the six months ended June 30, 2017. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets and future development plans. Our estimates of future cash flows attributable to our properties could decline if commodity prices decline, which may result in additional impairment expense. As of June 30, 2017, we continued to carry the costs of undeveloped properties of approximately $205.7 million on our Consolidated Balance Sheet, which is related to the Marcellus and Utica Shale and for which we currently have development, trade or lease extension plans. The expense incurred during the first six months of 2016 included proved properties of approximately $34.8 million in impairment related to undeveloped leases that expired or are expected to expire without being developed, the majority of which were in Butler County, Pennsylvania and Warrior North in Ohio.

Exploration Expense

Exploration Expense	6 Months Ended
	Jun. 30, 2017
Extractive Industries [Abstract]
Exploration Expense	16. EXPLORATION EXPENSE For the three and six months ended June 30, 2017, exploration expenses for continuing operations incurred were approximately $0.1 million and $0.3 million, respectively, and approximately $0.8 million and $1.7 million for the three and six months ended June 30, 2016, respectively. Approximately $0.2 million of the expense incurred in 2017 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals. Approximately $0.8 million of the expense incurred in 2016 was due to two exploratory wells that were abandoned at various stages, resulting in dry hole expense and the remaining 2016 expense of $0.9 million was due to geological and geophysical type expenditures.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	6 Months Ended
	Jun. 30, 2017
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of June 30, 2017, we had $600.3 million aggregate principal amount of outstanding Senior Notes, as shown in Note 7, Long-Term Debt • Rex Energy I, LLC; • Rex Energy Operating Corporation; • Rex Energy IV, LLC; • PennTex Resources Illinois, Inc.; and • R.E. Gas Development, LLC. The non-guarantor subsidiaries include certain consolidated subsidiaries, including R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of June 30, 2017, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016, the condensed consolidating statements of operations for the three and six months ended June 30, 2017 and 2016, and the condensed consolidating statements of cash flows for the six months ended June 30, 2017 and 2016. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 7,951 $ — $ 4,904 $ — $ 12,855 Accounts Receivable 23,755 — 7 — 23,762 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 6,982 — 335 — 7,317 Inventory, Prepaid Expenses and Other 1,392 — 610 — 2,002 Total Current Assets 40,080 — 5,904 — 45,984 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 977,665 — — — 977,665 Unevaluated Oil and Gas Properties 205,691 — — — 205,691 Other Property and Equipment 22,309 — — — 22,309 Wells and Facilities in Progress 59,807 — — — 59,807 Pipelines 21,289 — — — 21,289 Total Property and Equipment 1,286,761 — — — 1,286,761 Less: Accumulated Depreciation, Depletion and Amortization (434,483 ) — — — (434,483 ) Net Property and Equipment 852,278 — — — 852,278 Other Assets 2,488 — — — 2,488 Intercompany Receivables — — 1,037,626 (1,037,626 ) — Investment in Subsidiaries – Net (2,484 ) — (272,262 ) 274,746 — Long-Term Derivative Instruments 4,111 — 709 — 4,820 Total Assets $ 896,473 $ — $ 771,977 $ (762,880 ) $ 905,570 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 46,235 $ — $ — $ — $ 46,235 Current Maturities of Long-Term Debt 834 — — — 834 Accrued Liabilities 30,025 421 2,345 — 32,791 Short-Term Derivative Instruments 6,563 — — — 6,563 Total Current Liabilities 83,657 421 2,345 — 86,423 Long-Term Derivative Instruments 9,450 — — — 9,450 Term Loans, Net — — 136,163 — 136,163 Senior Notes, Net — — 648,820 — 648,820 Other Long-Term Debt 3,627 — — — 3,627 Other Deposits and Liabilities 7,731 — — — 7,731 Future Abandonment Cost 9,658 — — — 9,658 Intercompany Payables 1,033,962 3,664 — (1,037,626 ) — Total Liabilities 1,148,085 4,085 787,328 (1,037,626 ) 901,872 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 651,659 (177,144 ) 651,659 Accumulated Deficit (428,756 ) (4,085 ) (667,021 ) 451,890 (647,972 ) Total Stockholders’ Equity (251,612 ) (4,085 ) (15,351 ) 274,746 3,698 Total Liabilities and Stockholders’ Equity $ 896,473 $ — $ 771,977 $ (762,880 ) $ 905,570 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 47,457 $ — $ — $ — $ 47,457 Other Operating Revenue 5 — — — 5 TOTAL OPERATING REVENUE 47,462 — — — 47,462 OPERATING EXPENSES Production and Lease Operating Expense 29,374 — — — 29,374 General and Administrative Expense 3,771 — 523 — 4,294 Gain on Disposal of Assets (124 ) — — — (124 ) Impairment Expense 3,032 — — — 3,032 Exploration Expense 99 — — — 99 Depreciation, Depletion, Amortization and Accretion 15,501 — — — 15,501 Other Operating (Income) Expense (99 ) 1 — — (98 ) TOTAL OPERATING EXPENSES 51,554 1 523 — 52,078 LOSS FROM OPERATIONS (4,092 ) (1 ) (523 ) — (4,616 ) OTHER INCOME (EXPENSE) Interest Expense (442 ) — (11,680 ) — (12,122 ) Gain (Loss) on Derivatives, Net 10,861 — (475 ) — 10,386 Other Income 20 — — — 20 Loss on Extinguishments of Debt — — (3,271 ) — (3,271 ) (Loss) Income From Equity in Consolidated Subsidiaries (1 ) — 6,346 (6,345 ) — TOTAL OTHER INCOME (EXPENSE) 10,438 — (9,080 ) (6,345 ) (4,987 ) INCOME BEFORE INCOME TAX 6,346 (1 ) (9,603 ) (6,345 ) (9,603 ) Income Tax Expense — — — — — NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ 6,346 $ (1 ) $ (9,603 ) $ (6,345 ) $ (9,603 ) Preferred Stock Dividends — — (598 ) — (598 ) NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 6,346 $ (1 ) $ (10,201 ) $ (6,345 ) $ (10,201 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 99,522 $ — $ — $ — $ 99,522 Other Operating Revenue 11 — — — 11 TOTAL OPERATING REVENUE 99,533 — — — 99,533 OPERATING EXPENSES Production and Lease Operating Expense 58,308 — — — 58,308 General and Administrative Expense 8,232 — 596 — 8,828 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Impairment Expense 4,577 — — — 4,577 Exploration Expense 319 — — — 319 Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 Other Operating (Income) Expense (119 ) 1 — — (118 ) TOTAL OPERATING EXPENSES 100,327 1 596 — 100,924 LOSS FROM OPERATIONS (794 ) (1 ) (596 ) — (1,391 ) OTHER INCOME (EXPENSE) Interest Expense (809 ) — (20,457 ) — (21,266 ) Gain (Loss) on Derivatives, Net 20,659 — (1,893 ) — 18,766 Other Expense (7 ) — — — (7 ) Loss on Extinguishments of Debt — — (3,022 ) — (3,022 ) (Loss) Income from Equity in Consolidated Subsidiaries (1 ) 19,048 (19,047 ) — TOTAL OTHER INCOME (EXPENSE) 19,842 — (6,324 ) (19,047 ) (5,529 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Income Tax Expense — — — — — INCOME (LOSS) FROM CONTINUING OPERATIONS 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Income (Loss) From Discontinued Operations, Net of Income Tax — — — — — NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ 19,048 $ (1 ) $ (6,920 ) $ (19,047 ) $ (6,920 ) Preferred Stock Dividends — — (1,196 ) — (1,196) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 19,048 $ (1 ) $ (8,116 ) $ (19,047 ) $ (8,116) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ 19,048 $ (1 ) $ (6,920 ) $ (19,047 ) $ (6,920 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 (Gain) Loss on Derivatives (20,659 ) — 1,893 — (18,766 ) Cash Settlements of Derivatives (5,525 ) — — — (5,525 ) Non-cash Dry Hole Expense 13 — — — 13 Equity-based Compensation Expense — — 571 — 571 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Loss on Extinguishments Debt — — 3,022 — 3,022 Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 12,431 — 12,431 Impairment Expense 4,577 — — — 4,577 Other Non-cash Income 41 — — — 41 Changes in operating assets and liabilities Accounts Receivable 7,232 — (3 ) — 7,229 Taxes Receivable — — 163 — 163 Inventory, Prepaid Expenses and Other Assets 638 — (586 ) — 52 Accounts Payable and Accrued Liabilities (1,484 ) — — — (1,484 ) Other Assets and Liabilities (1,104 ) — — — (1,104 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 31,787 (1 ) 10,571 (19,047 ) 23,310 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 4,063 1 (23,111 ) 19,047 — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 24,513 — — — 24,513 Acquisitions of Undeveloped Acreage (1,783 ) — — — (1,783 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (54,004 ) — — — (54,004 ) NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (27,211 ) 1 (23,111 ) 19,047 (31,274 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Line of Credit — — 171,000 — 171,000 Repayments of Long-Term Debt and Line of Credit — — (145,170 ) — (145,170 ) Repayments of Loans and Other Long-Term Debt (319 ) — — — (319 ) Debt Issuance Costs — — (7,791 ) — (7,791 ) Payment of Preferred Dividends in Arrears — — (598 ) — (598 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (319 ) — 17,441 — 17,122 NET INCREASE IN CASH 4,257 — 4,901 — 9,158 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 7,951 $ — $ 4,904 $ — $ 12,855 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 3,694 $ — $ 3 $ — $ 3,697 Accounts Receivable 22,609 — 2,839 — 25,448 Taxes Receivable — — 211 — 211 Short-Term Derivative Instruments 650 — 1,223 — 1,873 Inventory, Prepaid Expenses and Other 2,521 — 25 — 2,546 Total Current Assets 29,474 — 4,301 — 33,775 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,053,461 — — — 1,053,461 Unevaluated Oil and Gas Properties 215,794 — — — 215,794 Other Property and Equipment 21,401 — — — 21,401 Wells and Facilities in Progress 21,964 — — — 21,964 Pipelines 18,029 — — — 18,029 Total Property and Equipment 1,330,649 — — — 1,330,649 Less: Accumulated Depreciation, Depletion and Amortization (475,205 ) — — — (475,205 ) Net Property and Equipment 855,444 — — — 855,444 Other Assets 2,492 — — — 2,492 Intercompany Receivables — — 1,035,713 (1,035,713 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 500 — 1,712 — 2,212 Total Assets $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 40,712 $ — $ — $ — $ 40,712 Current Maturities of Long-Term Debt 764 — — — 764 Accrued Liabilities 32,328 421 4,458 — 37,207 Short-Term Derivative Instruments 25,025 — — — 25,025 Total Current Liabilities 98,829 421 4,458 — 103,708 Long-Term Derivative Instruments 7,227 — — — 7,227 Senior Secured Line of Credit, Net — — 113,785 — 113,785 Term Loans. Net — — — — — Senior Notes, Net — — 638,161 — 638,161 Other Long-Term Debt 3,409 — — — 3,409 Other Deposits and Liabilities 8,671 — — — 8,671 Future Abandonment Cost 8,736 — — — 8,736 Intercompany Payables 1,032,050 3,663 — (1,035,713 ) — Total Liabilities 1,158,922 4,084 756,404 (1,035,713 ) 883,697 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 650,669 (177,144 ) 650,669 Accumulated Deficit (450,544 ) (4,084 ) (493,332 ) 307,506 (640,454 ) Total Stockholders’ Equity (273,400 ) (4,084 ) 157,348 130,362 10,226 Total Liabilities and Stockholders’ Equity $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 31,271 $ — $ — $ — $ 31,271 Other Operating Expense (6 ) — — — (6 ) TOTAL OPERATING REVENUE 31,265 — — — 31,265 OPERATING EXPENSES Production and Lease Operating Expense 25,221 — — — 25,221 General and Administrative Expense 3,661 — 1,176 — 4,837 Loss on Disposal of Assets (4,307 ) — — — (4,307 ) Impairment Expense 25,139 — — — 25,139 Exploration Expense 803 — — — 803 Depreciation, Depletion, Amortization and Accretion 14,747 3 — — 14,750 Other Operating Expense 704 — — — 704 TOTAL OPERATING EXPENSES 65,968 3 1,176 — 67,147 LOSS FROM OPERATIONS (34,703 ) (3 ) (1,176 ) — (35,882 ) OTHER INCOME (EXPENSE) — Interest Expense (269 ) — (11,170 ) — (11,439 ) Loss on Derivatives, Net (29,169 ) — — — (29,169 ) Other Income 12 12 Debt Exchange Expense — — (533 ) — (533 ) Gain on Extinguishment of Debt — — 23,707 23,707 (Loss) Income From Equity in Consolidated Subsidiaries (54 ) 54 (65,341 ) 65,341 — TOTAL OTHER INCOME (EXPENSE) (29,480 ) 54 (53,337 ) 65,341 (17,422 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (64,183 ) 51 (54,513 ) 65,341 (53,304 ) Income Tax Benefit (Expense) 473 — (80 ) — 393 INCOME (LOSS) FROM CONTINUING OPERATIONS (63,710 ) 51 (54,593 ) 65,341 (52,911 ) Loss From Discontinued Operations, Net of Income Tax (1,629 ) (54 ) — — (1,683 ) NET INCOME (LOSS) (65,339 ) (3 ) (54,593 ) 65,341 (54,594 ) Preferred Stock Dividends — — (1,723 ) — (1,723 ) Effect of Preferred Stock Conversions — — 72,316 — 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (65,339 ) $ (3 ) $ 16,000 $ 65,341 $ 15,999 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 56,944 $ — $ — $ — $ 56,944 Other Revenue 7 — — — 7 TOTAL OPERATING REVENUE 56,951 — — — 56,951 OPERATING EXPENSES Production and Lease Operating Expense 49,671 1 — — 49,672 General and Administrative Expense 9,080 — 1,041 — 10,121 Gain on Disposal of Assets (4,295 ) — — — (4,295 ) Impairment Expense 35,780 — — — 35,780 Exploration Expense 1,737 1 — — 1,738 Depreciation, Depletion, Amortization and Accretion 31,249 13 — — 31,262 Other Operating Expense 1,030 — — — 1,030 TOTAL OPERATING EXPENSES 124,252 15 1,041 — 125,308 LOSS FROM OPERATIONS (67,301 ) (15 ) (1,041 ) — (68,357 ) OTHER INCOME (EXPENSE) Interest Expense (539 ) — (23,930 ) — (24,469 ) Loss on Derivatives, Net (25,120 ) — — — (25,120 ) Other Income 12 — — — 12 Debt Exchange Expense — — (9,014 ) — (9,014 ) Gain on Extinguishment of Debt — — 23,707 — 23,707 Income (Loss) From Equity in Consolidated Subsidiaries 79 (79 ) (104,226 ) 104,226 — TOTAL OTHER INCOME (EXPENSE) (25,568 ) (79 ) (113,463 ) 104,226 (34,884 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (92,869 ) (94 ) (114,504 ) 104,226 (103,241 ) Income Tax Expense (2,090 ) — (231 ) — (2,321 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (94,959 ) (94 ) (114,735 ) 104,226 (105,562 ) Loss From Discontinued Operations, Net of Income Tax (9,106 ) (67 ) — — (9,173 ) NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY (104,065 ) (161 ) (114,735 ) 104,226 (114,735 ) Preferred Stock Dividends — — (3,828 ) — (3,828 ) Effect of Preferred Stock Conversions — — 72,316 — 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (104,065 ) $ (161 ) $ (46,247 ) $ 104,226 $ (46,247 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (104,065 ) $ (161 ) $ (114,735 ) $ 104,226 $ (114,735 ) Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 36,293 52 — — 36,345 Loss on Derivatives, Net 25,120 — — — 25,120 Cash Settlements of Derivatives 30,340 — — — 30,340 Dry Hole Expense 870 — — — 870 Equity-based Compensation Expense — — 1,305 — 1,305 Gain on Disposal of Assets (4,338 ) — — — (4,338 ) Amortization of net Bond Discount and Deferred Debt Issuance Costs — — 538 — 538 Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 8,126 — 8,126 Gain on Extinguishment of Debt — — (23,757 ) — (23,757 ) Impairment Expense 39,330 (7 ) 39,323 (39,323 ) 39,323 Other Non-cash (Income) Expense (100 ) — 231 — 131 Changes in operating assets and liabilities Accounts Receivable (14,452 ) 103 (423 ) — (14,772 ) Inventory, Prepaid Expenses and Other Assets 1,093 — 25 — 1,118 Accounts Payable and Accrued Liabilities 15,148 — (4,723 ) — 10,425 Other Assets and Liabilities (651 ) (25 ) — — (676 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,588 (38 ) (94,090 ) 64,903 (4,637 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 2,035 109 62,759 (64,903 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 190 — — — 190 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,863 ) (37 ) — — (5,900 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (37,704 ) (34 ) — — (37,738 ) NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (21,881 ) 38 62,759 (64,903 ) (23,987 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 50,400 — 50,400 Repayments of Long Term Debt and Lines of Credit — — (15,230 ) — (15,230 ) Repayments of Loans and Other Long-Term Debt (361 ) — — — (361 ) Debt Issuance Costs — — (3,838 ) — (3,838 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (361 ) — 31,332 — 30,971 NET INCREASE IN CASH 2,346 — 1 — 2,347 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 3,435 $ — $ 3 $ — $ 3,438

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2017
Subsequent Events [Abstract]
Subsequent Events	18. SUBSEQUENT EVENTS Marketing Agreement with BP Energy Company On August 1, 2017, we entered into a comprehensive marketing arrangement with BP Structured Products (“BP”) pursuant to which BP will market the majority of our liquid C3+ products stream and support several other marketing initiatives out of our Butler and Warrior North operating areas. Beginning January 1, 2018, BP will purchase the majority of our C3+ products stream at a fixed price differential to Mt. Bellevue for a four year term. The fixed priced differential compares favorably to 2016 and currently projected 2017 differentials, is expected to eliminate the wide fluctuations between summer and winter pricing during the term, and is expected to allow more flexibility in the timing for placement of wells into sales. As a result of the new marketing arrangement, we were able to reduce one of our firm transportation credit support obligations by approximately $14.1 million, which will in turn increase our available borrowing base under the Delayed Draw Term Facility by a similar amount. As part of the broader marketing initiatives, BP will also market a portion of our Warrior North gas at an improved differential to the current pricing. Sale of Salineville Waterline In July 2018, we entered into an agreement with Keystone Clearwater Solutions (“Keystone”) to sell a permanent waterline in Ohio, which provides fresh water for completions operations in our Warrior North operated area, to Keystone. Keystone will own and operate the waterline. In conjunction with the sale, we entered into a leasing arrangement with Keystone to maintain first right of refusal on available water. The purchase price of the waterline was approximately $7.0 million. We intend to account for this transaction as a sale-leaseback arrangement and, pursuant to ASC 360, continue to hold this asset as held and used as of June 30, 2017.

Recently Issued Accounting Pr25

Recently Issued Accounting Pronouncements (Policies)	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Recently Issued Accounting Pronouncements	In May 2014, the Financial Accounting Standards Board (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 February 2016, the FASB issued ASU 2016-02, Leases • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

Future Abandonment Cost (Tables

Future Abandonment Cost (Tables)	6 Months Ended
	Jun. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Future Abandonment Costs	We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) June 30, 2017 Beginning Balance at January 1, 2017 $ 9,865 Future Abandonment Obligation Incurred $ 1,062 Future Abandonment Obligation Settled $ (1,051 ) Future Abandonment Obligation Cancelled or Sold $ (262 ) Future Abandonment Obligation Revision of Estimated Obligation $ 57 Future Abandonment Obligation Accretion Expense $ 1,042 Total Future Abandonment Cost 1 $ 10,713 1

Discontinued Operations_Asset27

Discontinued Operations/Assets Held For Sale (Tables)	6 Months Ended
	Jun. 30, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Average Spot Price	For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of June 30, 2017, the first three of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds related to those measurement periods. As of June 30, 2017, we have the potential to receive up to $7.2 million of additional proceeds, during the eight remaining measurement periods. For additional information, see Note 8, Derivative Instruments and Fair Value Measurements Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (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).
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 assets and operations does not include any of our derivative contracts or positions related to our Illinois Basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the three and six month periods ended June 30, 2017 and 2016. For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2017 2016 2017 2016 Revenues: Oil Sales $ — $ 6,393 $ — $ 11,213 Total Operating Revenue — 6,393 — 11,213 Costs and Expenses: Production and Lease Operating Expense — 5,029 — 10,725 General and Administrative Expense — 659 — 1,437 Gain on Disposal of Assets — (2 ) — (43 ) Impairment Expense — — — 3,543 Exploration Expense — 85 — 143 Depreciation, Depletion, Amortization and Accretion — 2,186 — 5,083 Interest Expense — 1 — 3 Other Income — (2 ) — (3 ) Total Costs and Expenses — 7,956 — 20,888 Loss From Discontinued Operations, Before Income Taxes — (1,563 ) — (9,675 ) Income Tax Expense — (120 ) — 502 Loss From Discontinued Operations, Net of Taxes $ — $ (1,683 ) $ — $ (9,173 ) Production: Crude Oil (Bbls) — 150,980 — 308,720

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Components of Long-Term Debt and Lines of Credit	June 30, 2017 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 143,500 $ (4,072 ) $ (3,265 ) $ - $ 136,163 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ 23 $ (92 ) $ - $ 7,264 6.25% Senior Notes due 2022 5,363 - (73 ) - 5,290 1% / 8% Second Lien Senior Notes due 2020 587,606 (11,250 ) 26,915 32,995 636,266 $ 600,302 $ (11,227 ) $ 26,750 $ 32,995 $ 648,820 Other Long-Term Debt Long-Term Capital Leases - Equipment Financing Due March, 2021 $ 699 Due June, 2021 2,045 Due September, 2021 1,717 Total Capital Lease Obligations $ 4,461 Less: Current Portion of Capital Leases (834 ) $ 3,627 December 31, 2016 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Unamortized Deferred Gain on Debt Restructurings Net Carrying Value Senior Secured Line of Credit, Net Revolving Senior Credit Facility $ 117,670 $ - $ (3,885 ) $ - $ 113,785 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,573 $ 26 $ (107 ) $ - $ 7,492 6.25% Senior Notes due 2022 5,648 - (82 ) - 5,566 1% / 8% Second Lien Senior Notes due 2020 587,956 (3,627 ) 8,098 32,676 625,103 $ 601,177 $ (3,601 ) $ 7,909 $ 32,676 $ 638,161 Other Long-Term Debt Long-Term Capital Leases and Other Notes Payable- Equipment Financing Due March, 2021 $ 760 Due June, 2021 2,225 Due September, 2021 1,174 Total Capital Lease Obligations $ 4,159 Other Notes Payable 14 Total Capital Lease and Note Payable Obligations $ 4,173 Less: Current Portion of Capital Leases and Other Notes Payable (764 ) $ 3,409
Principal Maturity Schedule for Debt Outstanding	The following is the principal maturity schedule for debt outstanding as of June 30, 2017: 2017 $ 399 2018 908 2019 1,076 2020 739,715 2021 802 Thereafter 5,363 Total (a) $ 748,263 (a) Excludes $15.3 million of net unamortized premium/discount, $23.5 million of net unamortized debt issuance costs, and $33.0 million of unamortized deferred gain on debt restructurings.

Derivative Instruments And Fa29

Derivative Instruments And Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2017
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	Derivative Instruments from Continuing Operations The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016: For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2017 2016 2017 2016 Oil $ 791 $ (2,494 ) $ 1,934 $ (2,169 ) Natural Gas 6,132 (18,666 ) 6,072 (13,302 ) NGLs 3,938 (8,093 ) 12,653 (9,714 ) Refined Products — 84 — 65 Contingent Consideration (475 ) — (1,893 ) — Gain (Loss) on Derivatives, Net $ 10,386 $ (29,169 ) $ 18,766 $ (25,120 )
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2017 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2017 - Swaps 30,000 Bbls $ — $ — $ — $ 54.00 $ 175 2017 - Three-Way Collars 78,000 Bbls 39.62 49.23 61.35 — 228 2018 - Swaps 60,000 Bbls — — — 54.00 350 2018 - Collars 18,000 Bbls — 53.00 60.00 — 113 2018 - Three-Way Collars 60,000 Bbls 43.00 52.00 62.30 — 211 2019 - Swaps 31,500 Bbls — — — 51.00 21 2019 - Three-Way Collars 21,000 Bbls 37.50 47.50 59.00 — 6 2020 - Swaps 24,000 Bbls — — — 51.00 21 2020 - Three-Way Collars 3,000 Bbls 37.50 47.50 59.00 — 1 2021 - Swaps 6,000 Bbls — — — 51.00 5 331,500 Bbls $ 1,131 Natural Gas 2017 - Swaps 5,990,000 Mcf — — — 3.12 $ 234 2017 - Swaptions 1,200,000 Mcf — — — 3.33 269 2017 - Cap Swaps 1,800,000 Mcf 2.25 — — 2.70 (703 ) 2017 - Collars 1,100,000 Mcf — 2.62 3.25 — (48 ) 2017 - Three-Way Collars 8,490,000 Mcf 2.29 2.98 3.86 — 669 2017 - Calls 1,500,000 Mcf — — 3.64 — (154 ) 2017 - Basis Swaps - Dominion South 5,635,000 Mcf — — — (0.80 ) (688 ) 2017 - Basis Swaps - Texas Gas 7,360,000 Mcf — — — (0.13 ) 4 2018 - Swaps 15,335,000 Mcf — — — 3.10 1,321 2018 - Swaptions — Mcf — — — — (143 ) 2018 - Three-Way Collars 8,775,000 Mcf 2.30 2.89 3.58 — 228 2018 - Calls 5,810,000 Mcf — — 3.97 — (527 ) 2018 - Collars 450,000 Mcf — 3.20 3.65 — 38 2018 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.83 ) (3,029 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf (0.13 ) 8 2019 - Swaps 6,350,000 Mcf — — — 2.91 26 2019 - Three-Way Collars 5,000,000 Mcf 2.35 2.85 3.60 — 46 2019 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.84 ) (3,256 ) 2020 - Swaps 3,660,000 Mcf — — — 2.90 (29 ) 2020 - Three-Way Collars 1,810,000 Mcf 2.35 2.85 3.60 — 46 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.84 ) (1,722 ) 2021 - Swaps 900,000 Mcf — — — 2.90 (7 ) 2021 - Three-Way Collars 300,000 Mcf 2.35 2.85 3.60 — 12 2021 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (526 ) 143,535,000 Mcf $ (9,509 ) NGLs 2017 - C3+ NGL Swaps 841,000 Bbls — — — 29.70 $ (779 ) 2017 - Ethane Swaps 450,000 Bbls — — — 10.50 (54 ) 2018 - C3+ NGL Swaps 1,110,000 Bbls — — — 31.50 3,102 2018 - Ethane Swaps 750,000 Bbls — — — 13.02 539 2019 - C3+ NGL Swaps 353,250 Bbls — — — 26.04 200 2019 - C5 Collars 113,040 Bbls — 44.94 55.02 — 5 2019 - Ethane Swaps 480,000 Bbls — — — 13.02 130 2020 - C3+ NGL Swaps 135,000 Bbls — — — 24.78 256 2020 - C5 Collars 28,260 Bbls — 44.94 55.02 — 1 2020 - Ethane Swaps 48,000 Bbls — — — 13.44 (3 ) 2021 - C3+ NGL Swap 30,000 Bbls — — — 24.78 62 2021 - Ethane Swaps 9,000 Bbls — — — 13.44 (1 ) 4,347,550 Bbls $ 3,458
Combined Fair Value of Derivatives	The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 is summarized below: June 30, December 31, ($ in Thousands) 2017 2016 Short-Term Derivative Assets: Crude Oil—Three-Way Collars $ 333 $ — Crude Oil—Swaps 350 — Crude Oil—Collars 113 — NGL—Swaps 3,210 — Natural Gas—Swaps 1,292 206 Natural Gas—Cap Swaps — 61 Natural Gas—Collars 63 — Natural Gas—Basis Swaps 211 232 Natural Gas—Three-Way Collars 1,141 151 Natural Gas—Swaption 269 — Contingent Consideration - Sale of Illinois Basin 335 1,223 Total Short-Term Derivative Assets $ 7,317 $ 1,873 Long-Term Derivative Assets: Crude Oil—Three-Way Collars $ 113 $ — Crude Oil—Swaps 222 — NGL—Swaps 2,553 — NGL—Collars 14 — Natural Gas—Swaps 760 206 Natural Gas—Basis Swaps 53 293 Natural Gas—Three-Way Collars 396 — Contingent Consideration - Sale of Illinois Basin 709 1,713 Total Long-Term Derivative Assets $ 4,820 $ 2,212 Total Derivative Assets $ 12,137 $ 4,085 Short-Term Derivative Liabilities: Crude Oil—Collars $ — $ (86 ) Crude Oil—Deferred Put Spread — (9 ) Crude Oil—Three-Way Collars — (132 ) Crude Oil—Swaps — (220 ) NGL—Swaps (2,211 ) (9,895 ) Natural Gas—Three-Way Collars (368 ) (2,397 ) Natural Gas—Cap Swaps (703 ) (3,364 ) Natural Gas—Collars (73 ) (873 ) Natural Gas—Basis Swaps (2,291 ) (640 ) Natural Gas—Call (418 ) (1,478 ) Natural Gas—Swaption (71 ) (1,258 ) Natural Gas—Swaps (428 ) (4,673 ) Total Short - Term Derivative Liabilities $ (6,563 ) $ (25,025 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars $ — $ (58 ) Crude Oil—Swaps — (146 ) NGL—Swaps (100 ) (2,200 ) NGL—Collars (8 ) — Natural Gas—Swaps (79 ) (1,004 ) Natural Gas—Swaption (72 ) (167 ) Natural Gas—Basis Swaps (8,760 ) (1,260 ) Natural Gas—Collars — (115 ) Natural Gas—Call (263 ) (491 ) Natural Gas—Three-Way Collars (168 ) (1,786 ) Total Long-Term Derivative Liabilities $ (9,450 ) $ (7,227 ) Total Derivative Liabilities $ (16,013 ) $ (32,252 )
Fair Value 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 June 30, 2017 ($ in Thousands) Total Carrying Value as of June 30, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (3,876 ) $ — $ (3,876 ) $ — Fair Value Measurements at December 31, 2016 ($ in Thousands) Total Carrying Value as of December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (28,167 ) $ — $ (28,167 ) $ —
Financial Instruments Not Recorded at Fair Value	The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: June 30, 2017 December 31, 2016 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net $ 648,820 $ 288,156 $ 638,161 $ 147,605 Secured Line of Credit, Net of Issuance Costs — — 113,785 113,785 Term Loans, Net 136,163 136,163 — — Capital Leases and Other Obligations 4,461 3,074 4,173 3,234 Total $ 789,444 $ 427,393 $ 756,119 $ 264,624

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Schedule of Income Tax Included in Continuing Operations	Income tax included in continuing operations was as follows: Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2017 2016 2017 2016 Income Tax Benefit (Expense) $ — $ 393 $ — $ (2,321 ) Effective Tax Rate 0.0 % 0.7 % 0.0 % -2.2 %

Employee Benefit And Equity P31

Employee Benefit And Equity Plans (Tables)	6 Months Ended
	Jun. 30, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Issued and Outstanding Stock Options	A summary of the status of our issued and outstanding stock options as of June 30, 2017 is as follows: Outstanding Exercisable Exercise Price Number Outstanding at June 30, 2017 Weighted-Average Exercise Price Number Exercisable at June 30, 2017 Weighted-Average Exercise Price 9.70 2,750 $ 9.70 918 $ 9.70 16.90 75,352 $ 16.90 25,125 $ 16.90 40.50 4,000 $ 40.50 — $ 40.50 49.00 4,000 $ 49.00 666 $ 49.00 50.40 3,070 $ 50.40 3,070 $ 50.40 95.00 5,000 $ 95.00 5,000 $ 95.00 99.90 12,959 $ 99.90 12,959 $ 99.90 104.20 2,217 $ 104.20 2,217 $ 104.20 223.40 3,000 $ 223.40 3,000 $ 223.40 112,348 $ 39.91 52,955 $ 62.16
Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock	Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions: Year Ended December 31, 2015 Expected Dividend Yield 0.0 % Risk-Free Interest Rate 1.0 % Expected Volatility – Rex Energy 58.6 % Expected Volatility – Peer Group 29.8%-85.0% Market Index 35.6 % Expected Life Three Years
Summary of Nonvested Restricted Stock Activity	A summary of the restricted stock activity for the six months ended June 30, 2017 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2016 242,824 $ 26.34 Awards 101,237 5.18 Forfeitures (19,185 ) 86.78 Vested (39,278 ) 22.18 Restricted stock awards, as of June 30, 2017 $ 285,598 $ 15.35

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	As of June 30, 2017, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2017, was approximately $0.2 million and $0.5 million, respectively, and $0.3 million and $0.6 million for the three and six months ended June 30, 2016, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2017 $ 505 2018 565 2019 563 2020 422 2021 — Thereafter — Total $ 2,055
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) 2017 $ 22,281 2018 46,241 2019 46,408 2020 45,123 2021 42,204 Thereafter 464,028 Total $ 666,285
Fee for Unconventional Gas Wells	The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates: <$2.25(a) $2.26 - $2.99(a) $3.00 - $4.99(a) $5.00 - $5.99(a) >$5.99(a) Year One $ 40,200 $ 45,300 $ 50,300 $ 55,300 $ 60,400 Year Two $ 30,200 $ 35,200 $ 40,200 $ 45,300 $ 55,300 Year Three $ 25,200 $ 30,200 $ 30,200 $ 40,200 $ 50,300 Year 4 – 10 $ 10,100 $ 15,100 $ 20,100 $ 20,100 $ 20,100 Year 11 – 15 $ 5,000 $ 5,000 $ 10,100 $ 10,100 $ 10,100 (a )

Earnings Per Common Share (Tabl

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

Condensed Consolidating Finan34

Condensed Consolidating Financial Information (Tables)	6 Months Ended
	Jun. 30, 2017
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 7,951 $ — $ 4,904 $ — $ 12,855 Accounts Receivable 23,755 — 7 — 23,762 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 6,982 — 335 — 7,317 Inventory, Prepaid Expenses and Other 1,392 — 610 — 2,002 Total Current Assets 40,080 — 5,904 — 45,984 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 977,665 — — — 977,665 Unevaluated Oil and Gas Properties 205,691 — — — 205,691 Other Property and Equipment 22,309 — — — 22,309 Wells and Facilities in Progress 59,807 — — — 59,807 Pipelines 21,289 — — — 21,289 Total Property and Equipment 1,286,761 — — — 1,286,761 Less: Accumulated Depreciation, Depletion and Amortization (434,483 ) — — — (434,483 ) Net Property and Equipment 852,278 — — — 852,278 Other Assets 2,488 — — — 2,488 Intercompany Receivables — — 1,037,626 (1,037,626 ) — Investment in Subsidiaries – Net (2,484 ) — (272,262 ) 274,746 — Long-Term Derivative Instruments 4,111 — 709 — 4,820 Total Assets $ 896,473 $ — $ 771,977 $ (762,880 ) $ 905,570 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 46,235 $ — $ — $ — $ 46,235 Current Maturities of Long-Term Debt 834 — — — 834 Accrued Liabilities 30,025 421 2,345 — 32,791 Short-Term Derivative Instruments 6,563 — — — 6,563 Total Current Liabilities 83,657 421 2,345 — 86,423 Long-Term Derivative Instruments 9,450 — — — 9,450 Term Loans, Net — — 136,163 — 136,163 Senior Notes, Net — — 648,820 — 648,820 Other Long-Term Debt 3,627 — — — 3,627 Other Deposits and Liabilities 7,731 — — — 7,731 Future Abandonment Cost 9,658 — — — 9,658 Intercompany Payables 1,033,962 3,664 — (1,037,626 ) — Total Liabilities 1,148,085 4,085 787,328 (1,037,626 ) 901,872 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 651,659 (177,144 ) 651,659 Accumulated Deficit (428,756 ) (4,085 ) (667,021 ) 451,890 (647,972 ) Total Stockholders’ Equity (251,612 ) (4,085 ) (15,351 ) 274,746 3,698 Total Liabilities and Stockholders’ Equity $ 896,473 $ — $ 771,977 $ (762,880 ) $ 905,570 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 3,694 $ — $ 3 $ — $ 3,697 Accounts Receivable 22,609 — 2,839 — 25,448 Taxes Receivable — — 211 — 211 Short-Term Derivative Instruments 650 — 1,223 — 1,873 Inventory, Prepaid Expenses and Other 2,521 — 25 — 2,546 Total Current Assets 29,474 — 4,301 — 33,775 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,053,461 — — — 1,053,461 Unevaluated Oil and Gas Properties 215,794 — — — 215,794 Other Property and Equipment 21,401 — — — 21,401 Wells and Facilities in Progress 21,964 — — — 21,964 Pipelines 18,029 — — — 18,029 Total Property and Equipment 1,330,649 — — — 1,330,649 Less: Accumulated Depreciation, Depletion and Amortization (475,205 ) — — — (475,205 ) Net Property and Equipment 855,444 — — — 855,444 Other Assets 2,492 — — — 2,492 Intercompany Receivables — — 1,035,713 (1,035,713 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 500 — 1,712 — 2,212 Total Assets $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 40,712 $ — $ — $ — $ 40,712 Current Maturities of Long-Term Debt 764 — — — 764 Accrued Liabilities 32,328 421 4,458 — 37,207 Short-Term Derivative Instruments 25,025 — — — 25,025 Total Current Liabilities 98,829 421 4,458 — 103,708 Long-Term Derivative Instruments 7,227 — — — 7,227 Senior Secured Line of Credit, Net — — 113,785 — 113,785 Term Loans. Net — — — — — Senior Notes, Net — — 638,161 — 638,161 Other Long-Term Debt 3,409 — — — 3,409 Other Deposits and Liabilities 8,671 — — — 8,671 Future Abandonment Cost 8,736 — — — 8,736 Intercompany Payables 1,032,050 3,663 — (1,035,713 ) — Total Liabilities 1,158,922 4,084 756,404 (1,035,713 ) 883,697 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 650,669 (177,144 ) 650,669 Accumulated Deficit (450,544 ) (4,084 ) (493,332 ) 307,506 (640,454 ) Total Stockholders’ Equity (273,400 ) (4,084 ) 157,348 130,362 10,226 Total Liabilities and Stockholders’ Equity $ 885,522 $ — $ 913,752 $ (905,351 ) $ 893,923
Condensed Consolidating Statements of Operations	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 47,457 $ — $ — $ — $ 47,457 Other Operating Revenue 5 — — — 5 TOTAL OPERATING REVENUE 47,462 — — — 47,462 OPERATING EXPENSES Production and Lease Operating Expense 29,374 — — — 29,374 General and Administrative Expense 3,771 — 523 — 4,294 Gain on Disposal of Assets (124 ) — — — (124 ) Impairment Expense 3,032 — — — 3,032 Exploration Expense 99 — — — 99 Depreciation, Depletion, Amortization and Accretion 15,501 — — — 15,501 Other Operating (Income) Expense (99 ) 1 — — (98 ) TOTAL OPERATING EXPENSES 51,554 1 523 — 52,078 LOSS FROM OPERATIONS (4,092 ) (1 ) (523 ) — (4,616 ) OTHER INCOME (EXPENSE) Interest Expense (442 ) — (11,680 ) — (12,122 ) Gain (Loss) on Derivatives, Net 10,861 — (475 ) — 10,386 Other Income 20 — — — 20 Loss on Extinguishments of Debt — — (3,271 ) — (3,271 ) (Loss) Income From Equity in Consolidated Subsidiaries (1 ) — 6,346 (6,345 ) — TOTAL OTHER INCOME (EXPENSE) 10,438 — (9,080 ) (6,345 ) (4,987 ) INCOME BEFORE INCOME TAX 6,346 (1 ) (9,603 ) (6,345 ) (9,603 ) Income Tax Expense — — — — — NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ 6,346 $ (1 ) $ (9,603 ) $ (6,345 ) $ (9,603 ) Preferred Stock Dividends — — (598 ) — (598 ) NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 6,346 $ (1 ) $ (10,201 ) $ (6,345 ) $ (10,201 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 99,522 $ — $ — $ — $ 99,522 Other Operating Revenue 11 — — — 11 TOTAL OPERATING REVENUE 99,533 — — — 99,533 OPERATING EXPENSES Production and Lease Operating Expense 58,308 — — — 58,308 General and Administrative Expense 8,232 — 596 — 8,828 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Impairment Expense 4,577 — — — 4,577 Exploration Expense 319 — — — 319 Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 Other Operating (Income) Expense (119 ) 1 — — (118 ) TOTAL OPERATING EXPENSES 100,327 1 596 — 100,924 LOSS FROM OPERATIONS (794 ) (1 ) (596 ) — (1,391 ) OTHER INCOME (EXPENSE) Interest Expense (809 ) — (20,457 ) — (21,266 ) Gain (Loss) on Derivatives, Net 20,659 — (1,893 ) — 18,766 Other Expense (7 ) — — — (7 ) Loss on Extinguishments of Debt — — (3,022 ) — (3,022 ) (Loss) Income from Equity in Consolidated Subsidiaries (1 ) 19,048 (19,047 ) — TOTAL OTHER INCOME (EXPENSE) 19,842 — (6,324 ) (19,047 ) (5,529 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Income Tax Expense — — — — — INCOME (LOSS) FROM CONTINUING OPERATIONS 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Income (Loss) From Discontinued Operations, Net of Income Tax — — — — — NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ 19,048 $ (1 ) $ (6,920 ) $ (19,047 ) $ (6,920 ) Preferred Stock Dividends — — (1,196 ) — (1,196) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 19,048 $ (1 ) $ (8,116 ) $ (19,047 ) $ (8,116) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 31,271 $ — $ — $ — $ 31,271 Other Operating Expense (6 ) — — — (6 ) TOTAL OPERATING REVENUE 31,265 — — — 31,265 OPERATING EXPENSES Production and Lease Operating Expense 25,221 — — — 25,221 General and Administrative Expense 3,661 — 1,176 — 4,837 Loss on Disposal of Assets (4,307 ) — — — (4,307 ) Impairment Expense 25,139 — — — 25,139 Exploration Expense 803 — — — 803 Depreciation, Depletion, Amortization and Accretion 14,747 3 — — 14,750 Other Operating Expense 704 — — — 704 TOTAL OPERATING EXPENSES 65,968 3 1,176 — 67,147 LOSS FROM OPERATIONS (34,703 ) (3 ) (1,176 ) — (35,882 ) OTHER INCOME (EXPENSE) — Interest Expense (269 ) — (11,170 ) — (11,439 ) Loss on Derivatives, Net (29,169 ) — — — (29,169 ) Other Income 12 12 Debt Exchange Expense — — (533 ) — (533 ) Gain on Extinguishment of Debt — — 23,707 23,707 (Loss) Income From Equity in Consolidated Subsidiaries (54 ) 54 (65,341 ) 65,341 — TOTAL OTHER INCOME (EXPENSE) (29,480 ) 54 (53,337 ) 65,341 (17,422 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (64,183 ) 51 (54,513 ) 65,341 (53,304 ) Income Tax Benefit (Expense) 473 — (80 ) — 393 INCOME (LOSS) FROM CONTINUING OPERATIONS (63,710 ) 51 (54,593 ) 65,341 (52,911 ) Loss From Discontinued Operations, Net of Income Tax (1,629 ) (54 ) — — (1,683 ) NET INCOME (LOSS) (65,339 ) (3 ) (54,593 ) 65,341 (54,594 ) Preferred Stock Dividends — — (1,723 ) — (1,723 ) Effect of Preferred Stock Conversions — — 72,316 — 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (65,339 ) $ (3 ) $ 16,000 $ 65,341 $ 15,999 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 56,944 $ — $ — $ — $ 56,944 Other Revenue 7 — — — 7 TOTAL OPERATING REVENUE 56,951 — — — 56,951 OPERATING EXPENSES Production and Lease Operating Expense 49,671 1 — — 49,672 General and Administrative Expense 9,080 — 1,041 — 10,121 Gain on Disposal of Assets (4,295 ) — — — (4,295 ) Impairment Expense 35,780 — — — 35,780 Exploration Expense 1,737 1 — — 1,738 Depreciation, Depletion, Amortization and Accretion 31,249 13 — — 31,262 Other Operating Expense 1,030 — — — 1,030 TOTAL OPERATING EXPENSES 124,252 15 1,041 — 125,308 LOSS FROM OPERATIONS (67,301 ) (15 ) (1,041 ) — (68,357 ) OTHER INCOME (EXPENSE) Interest Expense (539 ) — (23,930 ) — (24,469 ) Loss on Derivatives, Net (25,120 ) — — — (25,120 ) Other Income 12 — — — 12 Debt Exchange Expense — — (9,014 ) — (9,014 ) Gain on Extinguishment of Debt — — 23,707 — 23,707 Income (Loss) From Equity in Consolidated Subsidiaries 79 (79 ) (104,226 ) 104,226 — TOTAL OTHER INCOME (EXPENSE) (25,568 ) (79 ) (113,463 ) 104,226 (34,884 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (92,869 ) (94 ) (114,504 ) 104,226 (103,241 ) Income Tax Expense (2,090 ) — (231 ) — (2,321 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (94,959 ) (94 ) (114,735 ) 104,226 (105,562 ) Loss From Discontinued Operations, Net of Income Tax (9,106 ) (67 ) — — (9,173 ) NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY (104,065 ) (161 ) (114,735 ) 104,226 (114,735 ) Preferred Stock Dividends — — (3,828 ) — (3,828 ) Effect of Preferred Stock Conversions — — 72,316 — 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (104,065 ) $ (161 ) $ (46,247 ) $ 104,226 $ (46,247 )
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ 19,048 $ (1 ) $ (6,920 ) $ (19,047 ) $ (6,920 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 (Gain) Loss on Derivatives (20,659 ) — 1,893 — (18,766 ) Cash Settlements of Derivatives (5,525 ) — — — (5,525 ) Non-cash Dry Hole Expense 13 — — — 13 Equity-based Compensation Expense — — 571 — 571 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Loss on Extinguishments Debt — — 3,022 — 3,022 Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 12,431 — 12,431 Impairment Expense 4,577 — — — 4,577 Other Non-cash Income 41 — — — 41 Changes in operating assets and liabilities Accounts Receivable 7,232 — (3 ) — 7,229 Taxes Receivable — — 163 — 163 Inventory, Prepaid Expenses and Other Assets 638 — (586 ) — 52 Accounts Payable and Accrued Liabilities (1,484 ) — — — (1,484 ) Other Assets and Liabilities (1,104 ) — — — (1,104 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 31,787 (1 ) 10,571 (19,047 ) 23,310 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 4,063 1 (23,111 ) 19,047 — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 24,513 — — — 24,513 Acquisitions of Undeveloped Acreage (1,783 ) — — — (1,783 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (54,004 ) — — — (54,004 ) NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (27,211 ) 1 (23,111 ) 19,047 (31,274 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Line of Credit — — 171,000 — 171,000 Repayments of Long-Term Debt and Line of Credit — — (145,170 ) — (145,170 ) Repayments of Loans and Other Long-Term Debt (319 ) — — — (319 ) Debt Issuance Costs — — (7,791 ) — (7,791 ) Payment of Preferred Dividends in Arrears — — (598 ) — (598 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (319 ) — 17,441 — 17,122 NET INCREASE IN CASH 4,257 — 4,901 — 9,158 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 7,951 $ — $ 4,904 $ — $ 12,855 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (104,065 ) $ (161 ) $ (114,735 ) $ 104,226 $ (114,735 ) Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 36,293 52 — — 36,345 Loss on Derivatives, Net 25,120 — — — 25,120 Cash Settlements of Derivatives 30,340 — — — 30,340 Dry Hole Expense 870 — — — 870 Equity-based Compensation Expense — — 1,305 — 1,305 Gain on Disposal of Assets (4,338 ) — — — (4,338 ) Amortization of net Bond Discount and Deferred Debt Issuance Costs — — 538 — 538 Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 8,126 — 8,126 Gain on Extinguishment of Debt — — (23,757 ) — (23,757 ) Impairment Expense 39,330 (7 ) 39,323 (39,323 ) 39,323 Other Non-cash (Income) Expense (100 ) — 231 — 131 Changes in operating assets and liabilities Accounts Receivable (14,452 ) 103 (423 ) — (14,772 ) Inventory, Prepaid Expenses and Other Assets 1,093 — 25 — 1,118 Accounts Payable and Accrued Liabilities 15,148 — (4,723 ) — 10,425 Other Assets and Liabilities (651 ) (25 ) — — (676 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,588 (38 ) (94,090 ) 64,903 (4,637 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 2,035 109 62,759 (64,903 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 190 — — — 190 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,863 ) (37 ) — — (5,900 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (37,704 ) (34 ) — — (37,738 ) NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (21,881 ) 38 62,759 (64,903 ) (23,987 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 50,400 — 50,400 Repayments of Long Term Debt and Lines of Credit — — (15,230 ) — (15,230 ) Repayments of Loans and Other Long-Term Debt (361 ) — — — (361 ) Debt Issuance Costs — — (3,838 ) — (3,838 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (361 ) — 31,332 — 30,971 NET INCREASE IN CASH 2,346 — 1 — 2,347 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 3,435 $ — $ 3 $ — $ 3,438

Basis of Presentation and Pri35

Basis of Presentation and Principles of Consolidation - Additional Information (Details)	May 12, 2017shares	Jun. 30, 2017shares	Mar. 31, 2017shares	Dec. 31, 2016shares
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Reverse stock split		On May 5, 2017, the Company’s common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017.
Common Stock, shares issued	9,900,000	9,952,861	99,000,000	9,787,146
Common Stock
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Reverse stock split	one-for-ten
Stockholders' equity, reverse stock split ratio	0.1

Future Abandonment Cost - Addit

Future Abandonment Cost - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 500	$ 100	$ 1,042	$ 400

Future Abandonment Cost (Detail

Future Abandonment Cost (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance at January 1, 2017				$ 9,865
Future Abandonment Obligation Incurred				1,062
Future Abandonment Obligation Settled				(1,051)
Future Abandonment Obligation Cancelled or Sold				(262)
Future Abandonment Obligation Revision of Estimated Obligation				57
Future Abandonment Obligation Accretion Expense		$ 500	$ 100	1,042	$ 400
Total Future Abandonment Cost	[1]	$ 10,713		$ 10,713
[1]	Includes approximately $1.1 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Future Abandonment Cost (Parent

Future Abandonment Cost (Parenthetical) (Details) $ in Millions	Jun. 30, 2017USD ($)
Accrued Liablities | Remediation Property for Sale, Abandonment or Disposal
Asset Retirement Obligations [Line Items]
Short-term future abandonment costs	$ 1.1

Discontinued Operations_ Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details) - Illinois Basin Operations - Discontinued Operations Assets Held For Sale	Jun. 14, 2016USD ($)	Jun. 30, 2017USD ($)aQuarterlyInstallmentbbl	Dec. 31, 2016USD ($)
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Additional proceeds from sale of oil and gas-related properties and assets			$ 38,000,000
Received purchase from deposits	$ 2,500,000
Proceeds receivable quarterly installments.	$ 900,000
Proceeds receivable quarterly installments beginning period.	Dec. 31, 2016
Proceeds receivable quarterly installments ending period.	Jun. 30, 2019
Expiration of quarterly measurement period number | QuarterlyInstallment		11
Expiration of quarterly measurement period number with average spot price | QuarterlyInstallment		3
Expiration of quarterly measurement period remaining number | QuarterlyInstallment		8
Additional proceeds receivable for first three quarterly installments.		$ 0
Area of land held for sale | a		76,000
Number of barrels net production per day | bbl		1,700
Assets or liabilities related to discontinued operation		$ 0	$ 0
Maximum
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Additional proceeds from sale of oil and gas property and equipment	$ 9,900,000
Additional proceeds receivable for remaining eight quarterly installments		$ 7,200,000

Average Spot Price (Details)

Average Spot Price (Details) - Illinois Basin Operations - Discontinued Operations Assets Held For Sale	6 Months Ended
	Jun. 30, 2017$ / bbl	[1]
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
[1]	Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).

Summary of Financial Informatio

Summary of Financial Information for Discontinued Operations (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)bbl	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)bbl
Revenues:
TOTAL OPERATING REVENUE	$ 47,462	$ 31,265	$ 99,533	$ 56,951
Costs and Expenses:
Production and Lease Operating Expense	29,374	25,221	58,308	49,672
General and Administrative Expense	4,294	4,837	8,828	10,121
Gain on Disposal of Assets	(124)	(4,307)	(1,959)	(4,295)
Impairment Expense	3,032	25,139	4,577	35,780
Exploration Expense	99	803	319	1,738
Depreciation, Depletion, Amortization and Accretion	15,501	14,750	30,969	31,262
Interest Expense	12,122	11,439	21,266	24,469
Other Income	$ (20)	(12)	$ 7	(12)
Loss From Discontinued Operations, Net of Taxes		(1,683)		(9,173)
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Revenues:
Oil Sales		6,393		11,213
TOTAL OPERATING REVENUE		6,393		11,213
Costs and Expenses:
Production and Lease Operating Expense		5,029		10,725
General and Administrative Expense		659		1,437
Gain on Disposal of Assets		(2)		(43)
Impairment Expense				3,543
Exploration Expense		85		143
Depreciation, Depletion, Amortization and Accretion		2,186		5,083
Interest Expense		1		3
Other Income		(2)		(3)
Total Costs and Expenses		7,956		20,888
Loss From Discontinued Operations, Before Income Taxes		(1,563)		(9,675)
Income Tax Expense		(120)		502
Loss From Discontinued Operations, Net of Taxes		$ (1,683)		$ (9,173)
Production:
Crude Oil (Bbls) | bbl		150,980		308,720

Business and Oil and Gas Prop42

Business and Oil and Gas Property Dispositions - Additional Information (Details)	Jan. 11, 2017USD ($)aMMcfeWell	May 20, 2016USD ($)Well	Mar. 01, 2016Well	Jan. 31, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)Well
Sale of Warrior South Assets
Business Acquisition And Dispositions [Line Items]
Net proceeds from sale of property | $	$ 24,100,000
Total consideration for the transaction | $	29,100,000
Amount held in escrow | $	$ 5,000,000
Gain on disposal of assets | $				$ 1,800,000
Number of gross wells	14
Production unit of oil | MMcfe	9
Sale of asset, acres | a	4,100
Sale of Warrior South Assets | Rex, MFC, and ABARTA
Business Acquisition And Dispositions [Line Items]
Total consideration for the transaction | $	$ 50,000,000
Production unit of oil | MMcfe	15
Sale of asset, acres | a	6,200
Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Amount received at closing of wells | $						$ 134,000,000
Payments for interest in wells that have been drilled or in process of being drilled | $						$ 103,000,000
Number of wells in which BSP Options to Participate in development						36
Percentage of working interest			65.00%
Number of wells in which BSP Options exercised to Participate in development						23
Number of producing wells						34
Number of wells committed for line and producing						45
Number of wells completed and waiting to go in line						4
Number of drilled well that is awaiting completion						7
Benefit Street Partners Limited Liability Corporation | Maximum
Business Acquisition And Dispositions [Line Items]
Total consideration for the transaction | $						$ 175,000,000
Percentage of working interest earned in acreage			20.00%
Benefit Street Partners Limited Liability Corporation | Minimum
Business Acquisition And Dispositions [Line Items]
Percentage of working interest earned in acreage			15.00%
Benefit Street Partners Limited Liability Corporation | Moraine East and Warrior North
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development			58
Benefit Street Partners Limited Liability Corporation | Butler County, Pennsylvania
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development			16
Percentage of estimated well costs			15.00%
Number of drilled and completed wells to be placed into service						16
Benefit Street Partners Limited Liability Corporation | Warrior North Ohio
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development			6
Percentage of estimated well costs			65.00%
Number of drilled and completed wells to be placed into service						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		300
Gain on disposition of oil and gas property | $					$ 4,600,000
Uncollectible accounts receivable written off | $					$ 200,000

Concentrations of Credit Risk -

Concentrations of Credit Risk - Additional Information (Details) - Sales - Customer Concentration Risk	6 Months Ended
	Jun. 30, 2017Customer
Purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	95.30%
Number of major customers	5
Largest single purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	50.70%

Long-Term Debt - Term Loan - Ad

Long-Term Debt - Term Loan - Additional Information (Details) - USD ($)	Apr. 28, 2017	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2017	Sep. 30, 2017
Debt Instrument [Line Items]
Deferred debt issuance costs		$ 3,500,000	$ 3,500,000
Original issue discount costs			$ 4,300,000
Amortization of debt issuance costs		200,000
Amortization of original issue discount costs		$ 200,000
Term loan yield maintenance ending period post effective date			30 months
Term loan yield maintenance effective date ending period			30 months
Term loan yield maintenance effective date after day one			30 months
Term loan yield maintenance ending period post effective date after day one			36 months
Term Loans, Net
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 300,000,000
Debt instrument, interest rate	4.00%
Commitment fee	3.50%
Prepayment of outstanding term loan percentage	100.00%
Percentage of prepayment on excess cash flow	50.00%
Criteria debt to EBITDAX ratio		233.00%	233.00%
Term Loans, Net | 30 Months After Effective Date
Debt Instrument [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	3.00%
Term Loans, Net | 36 Months After Effective Date
Debt Instrument [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	1.00%
Term Loans, Net | Maximum | Scenario, Forecast
Debt Instrument [Line Items]
Net senior secured debt to EBITDAX				325.00%
Term Loans, Net | Minimum | Scenario, Forecast
Debt Instrument [Line Items]
Criteria PDP coverage ratio				165.00%
EBITDAX to cash interest expense ratio					100.00%
EBITDAX to cash interest expense ratio thereafter					130.00%
Term Loans, Net | Adjusted LIBO Rate
Debt Instrument [Line Items]
Debt instrument, floor rate	1.00%
Debt instrument, margin rate	8.75%
8.00% Senior Secured Second Lien Notes due 2020
Debt Instrument [Line Items]
Debt instrument, interest rate	8.00%
Debt instrument, outstanding amount	$ 25,000,000
1.00% Senior Secured Second Lien Notes due 2020
Debt Instrument [Line Items]
Debt instrument, interest rate	1.00%
Second Lien Notes | Term Loans, Net
Debt Instrument [Line Items]
Percentage of prepayment on excess cash flow	75.00%
Second Lien Notes | Term Loans, Net | Maximum
Debt Instrument [Line Items]
Second lien notes outstanding	$ 287,950,000
Term Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	143,500,000
Line of credit facility, amount outstanding		$ 143,500,000	$ 143,500,000
Secured Delayed Draw Term Loan Facility
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity	$ 156,500,000
Line of credit facility, maturity date	Apr. 28, 2021
Line of credit facility, expiration date	Apr. 28, 2018
Line of credit facility expiration date potential extension period	1 year
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity		$ 46,300,000	$ 46,300,000

Long-Term Debt - Senior Credit

Long-Term Debt - Senior Credit Facility - Additional Information (Details) - Senior Credit Facility - USD ($) $ in Millions	Apr. 28, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Wrote off of unamortized debt issuance cost	$ 3.4
Line of credit facility, amount outstanding		$ 117.7

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Details) - USD ($) shares in Millions	Mar. 31, 2016	Jun. 30, 2017	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Apr. 28, 2017
Debt Instrument [Line Items]
Share of common stock				10.1
Gain recognized due to troubled debt exchanges			$ (533,000)			$ (9,014,000)
Shares issued	8.4
Fair value of stock issued	$ 6,500,000			$ 6,500,000
Accrued and unpaid interest	12,800,000			12,800,000
Third-party debt issuance costs					$ 7,791,000	3,838,000
Issuance of unrestricted common stock shares					0.1		22.7
Gain on Extinguishments of Debt		$ (3,271,000)	$ 23,707,000		$ (3,022,000)	$ 23,707,000
Trailing quarters fixed charge coverage ratio					225.00%
Fixed charge coverage ratio					105.00%
Senior Notes additional borrowings		75,200,000			$ 75,200,000
Senior Notes, Net
Debt Instrument [Line Items]
Gain on Extinguishments of Debt					400,000
Discount on Senior Notes, Net		$ 11,227,000			11,227,000		$ 3,601,000
Amortization of net premium					$ 3,800,000		7,600,000
Term Loans, Net
Debt Instrument [Line Items]
Interest rate								4.00%
Average interest rate		10.10%			9.99%
Capital Leases
Debt Instrument [Line Items]
Average interest rate		17.20%			14.40%
Senior Secured Line of Credit, Net
Debt Instrument [Line Items]
Average interest rate		4.90%			4.10%
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 troubled debt exchanges				0
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							45,700,000
Debt instrument redemption date					Apr. 1, 2018
Latest date for equity proceeds to be applied to optional Note redemption					Apr. 1, 2018
Percentage of notes that can be redeemed					35.00%
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%
2020 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 324,000,000			$ 324,000,000
Percentage of senior notes exchanged for new notes	92.60%
Retirement of notes					$ 900,000		$ 27,700,000
2022 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 309,100,000			$ 309,100,000
Percentage of senior notes exchanged for new notes	95.10%
8.875% Senior Notes | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate		8.875%			8.875%		8.875%
6.25% Senior Notes | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate		6.25%			6.25%		6.25%

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Term Loans, Net
Debt Instrument [Line Items]
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	$ 136,163
Term Loans, Net | Term Loan Draw - due April 2020
Debt Instrument [Line Items]
Principal	143,500
Unamortized net Premium / Discount	(4,072)
Unamortized Debt Issuance Costs	(3,265)
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	136,163
Senior Notes, Net
Debt Instrument [Line Items]
Principal	600,302	$ 601,177
Unamortized net Premium / Discount	(11,227)	(3,601)
Unamortized Debt Issuance Costs	26,750	7,909
Unamortized Deferred Gain on Debt Restructurings	32,995	32,676
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	648,820	638,161
Senior Notes, Net | 8.875% Senior Notes due 2020
Debt Instrument [Line Items]
Principal	7,333	7,573
Unamortized net Premium / Discount	23	26
Unamortized Debt Issuance Costs	(92)	(107)
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	7,264	7,492
Senior Notes, Net | 6.25% Senior Notes due 2022
Debt Instrument [Line Items]
Principal	5,363	5,648
Unamortized Debt Issuance Costs	(73)	(82)
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	5,290	5,566
Senior Notes, Net | 1% / 8% Second Lien Senior Notes due 2020
Debt Instrument [Line Items]
Principal	587,606	587,956
Unamortized net Premium / Discount	(11,250)	(3,627)
Unamortized Debt Issuance Costs	26,915	8,098
Unamortized Deferred Gain on Debt Restructurings	32,995	32,676
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	636,266	625,103
Other Long-Term Debt
Debt Instrument [Line Items]
Total Capital Lease Obligations	4,461	4,159
Less: Current Portion of Capital Leases	(834)
Non-Current Portion of Capital Leases	3,627
Other Notes Payable		14
Total Capital Lease and Note Payable Obligations		4,173
Less: Current Portion of Capital Leases and Other Notes Payable		(764)
Non-Current Portion of Capital Leases and Other Notes Payable		3,409
Other Long-Term Debt | Due March, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	699	760
Other Long-Term Debt | Due June, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	2,045	2,225
Other Long-Term Debt | Due September, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	$ 1,717	1,174
Senior Credit Facility | Revolving Senior Credit Facility
Debt Instrument [Line Items]
Principal		117,670
Unamortized Debt Issuance Costs		(3,885)
Senior Secured Line of Credit, Term Loans and Senior Notes, Net		$ 113,785

Components of Long-Term Debt 48

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Apr. 28, 2017
Term Loans, Net
Debt Instrument [Line Items]
Debt instrument, interest rate			4.00%
Debt instrument, maturity date, month and year	2020-04
8.875% Senior Notes due 2020 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate	8.875%	8.875%
Debt instrument, maturity year	2,020	2,020
6.25% Senior Notes due 2022 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate	6.25%	6.25%
Debt instrument, maturity year	2,022	2,022
1% / 8% Second Lien Senior Notes due 2020 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate	0.125%	0.125%
Debt instrument, maturity year	2,020	2,020
Due March, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-03	2021-03
Due June, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-06	2021-06
Due September, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-09	2021-09

Principal Maturity Schedule for

Principal Maturity Schedule for Debt Outstanding (Details) $ in Thousands	Jun. 30, 2017USD ($)
Debt Disclosure [Abstract]
2,017	$ 399
2,018	908
2,019	1,076
2,020	739,715
2,021	802
Thereafter	5,363
Total	$ 748,263	[1]
[1]	Excludes $15.3 million of net unamortized premium/discount, $23.5 million of net unamortized debt issuance costs, and $33.0 million of unamortized deferred gain on debt restructurings.

Principal Maturity Schedule f50

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) - Debt Restructurings $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)
Debt Instrument [Line Items]
Unamortized net Premium / Discount	$ 15.3
Unamortized Debt Issuance Costs	23.5
Unamortized deferred gain on debt restructurings	$ 33

Derivative Instruments and Fa51

Derivative Instruments and Fair Value Measurements - Additional Information (Details)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)Entity	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)
Derivatives Fair Value [Line Items]
Number of counterparties entered into an arrangements | Entity			2
Cash Settlements of Derivatives Received (Paid)			$ 5,525,000	$ (30,340,000)
Senior Notes	$ 600,300,000		600,300,000		$ 601,200,000
Derivative interest rate outstanding	0		0		0
Derivatives asset (liability)	3,900,000		3,900,000		28,200,000
Impairment Expense			4,600,000	35,800,000
Term Facility
Derivatives Fair Value [Line Items]
Senior Line of Credit	$ 143,500,000		143,500,000
Senior Credit Facility
Derivatives Fair Value [Line Items]
Senior Line of Credit					117,700,000
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Derivatives Fair Value [Line Items]
Fair value of contingent consideration derivative asset			1,200,000
Fair value of contingent consideration			$ 1,000,000		$ 2,900,000
Crude Oil
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through remainder of 2017	75.00%		75.00%
Natural Gas | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through remainder of 2017	90.00%		90.00%
Commodity hedged on annualized basis hedge through 2018	60.00%		60.00%
Natural Gas Liquids | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through remainder of 2017	70.00%		70.00%
Commodity hedged on annualized basis hedge through 2018	50.00%		50.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives Received (Paid)	$ (2,100,000)	$ 17,400,000	$ (5,500,000)	$ 30,500,000

Schedule of Location and Amount

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ 10,386	$ (29,169)	$ 18,766	$ (25,120)
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	791	(2,494)	1,934	(2,169)
Refined Products
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net		84		65
Natural Gas
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	6,132	(18,666)	6,072	(13,302)
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	3,938	$ (8,093)	12,653	$ (9,714)
Contingent Consideration
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (475)		$ (1,893)

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)$ / bbl$ / McfbblMcf
Crude Oil 2017 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	78,000
Put Option | $ / bbl	39.62
Floor | $ / bbl	49.23
Ceiling | $ / bbl	61.35
Derivatives asset (liability)	$ 228
Crude Oil 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	30,000
Swap | $ / bbl	54
Derivatives asset (liability)	$ 175
Crude Oil 2018 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	18,000
Floor | $ / bbl	53
Ceiling | $ / bbl	60
Derivatives asset (liability)	$ 113
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)	$ 211
Crude Oil 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	60,000
Swap | $ / bbl	54
Derivatives asset (liability)	$ 350
Crude Oil 2019 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	21,000
Put Option | $ / bbl	37.50
Floor | $ / bbl	47.50
Ceiling | $ / bbl	59
Derivatives asset (liability)	$ 6
Crude Oil 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	31,500
Swap | $ / bbl	51
Derivatives asset (liability)	$ 21
Crude Oil 2020 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	3,000
Put Option | $ / bbl	37.50
Floor | $ / bbl	47.50
Ceiling | $ / bbl	59
Derivatives asset (liability)	$ 1
Crude Oil 2020 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	24,000
Swap | $ / bbl	51
Derivatives asset (liability)	$ 21
Crude Oil 2021 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	6,000
Swap | $ / bbl	51
Derivatives asset (liability)	$ 5
Crude Oil
Derivatives Fair Value [Line Items]
Volume | bbl	331,500
Derivatives asset (liability)	$ 1,131
Natural Gas 2017 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	1,100,000
Floor | $ / Mcf	2.62
Ceiling | $ / Mcf	3.25
Derivatives asset (liability)	$ (48)
Natural Gas 2017 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	8,490,000
Put Option | $ / Mcf	2.29
Floor | $ / Mcf	2.98
Ceiling | $ / Mcf	3.86
Derivatives asset (liability)	$ 669
Natural Gas 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	5,990,000
Swap | $ / Mcf	3.12
Derivatives asset (liability)	$ 234
Natural Gas 2017 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	1,200,000
Swap | $ / Mcf	3.33
Derivatives asset (liability)	$ 269
Natural Gas 2017 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	1,800,000
Put Option | $ / Mcf	2.25
Swap | $ / Mcf	2.70
Derivatives asset (liability)	$ (703)
Natural Gas 2017 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	5,635,000
Swap | $ / Mcf	(0.80)
Derivatives asset (liability)	$ (688)
Natural Gas 2017 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	1,500,000
Ceiling | $ / Mcf	3.64
Derivatives asset (liability)	$ (154)
Natural Gas 2017 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	7,360,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ 4
Natural Gas 2018 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	450,000
Floor | $ / Mcf	3.20
Ceiling | $ / Mcf	3.65
Derivatives asset (liability)	$ 38
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)	$ 228
Natural Gas 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	15,335,000
Swap | $ / Mcf	3.10
Derivatives asset (liability)	$ 1,321
Natural Gas 2018 | Swaptions
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ (143)
Natural Gas 2018 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	12,775,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (3,029)
Natural Gas 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	5,810,000
Ceiling | $ / Mcf	3.97
Derivatives asset (liability)	$ (527)
Natural Gas 2018 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ 8
Natural Gas 2019 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	5,000,000
Put Option | $ / Mcf	2.35
Floor | $ / Mcf	2.85
Ceiling | $ / Mcf	3.60
Derivatives asset (liability)	$ 46
Natural Gas 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	6,350,000
Swap | $ / Mcf	2.91
Derivatives asset (liability)	$ 26
Natural Gas 2019 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	12,775,000
Swap | $ / Mcf	(0.84)
Derivatives asset (liability)	$ (3,256)
Natural Gas 2020 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	1,810,000
Put Option | $ / Mcf	2.35
Floor | $ / Mcf	2.85
Ceiling | $ / Mcf	3.60
Derivatives asset (liability)	$ 46
Natural Gas 2020 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	3,660,000
Swap | $ / Mcf	2.90
Derivatives asset (liability)	$ (29)
Natural Gas 2020 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,320,000
Swap | $ / Mcf	(0.84)
Derivatives asset (liability)	$ (1,722)
Natural Gas 2021 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	300,000
Put Option | $ / Mcf	2.35
Floor | $ / Mcf	2.85
Ceiling | $ / Mcf	3.60
Derivatives asset (liability)	$ 12
Natural Gas 2021 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	900,000
Swap | $ / Mcf	2.90
Derivatives asset (liability)	$ (7)
Natural Gas 2021 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (526)
Natural Gas 2022 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (526)
Natural Gas 2023 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (526)
Natural Gas 2024 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (526)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	143,535,000
Derivatives asset (liability)	$ (9,509)
Natural Gas Liquids Reserves 2017 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	841,000
Swap | $ / bbl	29.70
Derivatives asset (liability)	$ (779)
Natural Gas Liquids Reserves 2017 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	450,000
Swap | $ / bbl	10.50
Derivatives asset (liability)	$ (54)
Natural Gas Liquids Reserves 2018 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,110,000
Swap | $ / bbl	31.50
Derivatives asset (liability)	$ 3,102
Natural Gas Liquids Reserves 2018 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	750,000
Swap | $ / bbl	13.02
Derivatives asset (liability)	$ 539
Natural Gas Liquids Reserves 2019 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	353,250
Swap | $ / bbl	26.04
Derivatives asset (liability)	$ 200
Natural Gas Liquids Reserves 2019 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	480,000
Swap | $ / bbl	13.02
Derivatives asset (liability)	$ 130
Natural Gas Liquids Reserves 2019 | C5 Collars
Derivatives Fair Value [Line Items]
Volume | bbl	113,040
Floor | $ / bbl	44.94
Ceiling | $ / bbl	55.02
Derivatives asset (liability)	$ 5
Natural Gas Liquids Reserves 2020 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	135,000
Swap | $ / bbl	24.78
Derivatives asset (liability)	$ 256
Natural Gas Liquids Reserves 2020 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	48,000
Swap | $ / bbl	13.44
Derivatives asset (liability)	$ (3)
Natural Gas Liquids Reserves 2020 | C5 Collars
Derivatives Fair Value [Line Items]
Volume | bbl	28,260
Floor | $ / bbl	44.94
Ceiling | $ / bbl	55.02
Derivatives asset (liability)	$ 1
Natural Gas Liquids Reserves 2021 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	30,000
Swap | $ / bbl	24.78
Derivatives asset (liability)	$ 62
Natural Gas Liquids Reserves 2021 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	9,000
Swap | $ / bbl	13.44
Derivatives asset (liability)	$ (1)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	4,347,550
Derivatives asset (liability)	$ 3,458

Combined Fair Value of Derivati

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

Fair Value Hierarchy Table for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) - Commodity derivatives - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (3,876)	$ (28,167)
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (3,876)	$ (28,167)

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Carrying Amount
Derivatives Fair Value [Line Items]
Senior Notes, Net	$ 648,820	$ 638,161
Secured Line of Credit, Net of Issuance Costs		113,785
Term Loans, Net	136,163
Capital Leases and Other Obligations	4,461	4,173
Total	789,444	756,119
Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, Net	288,156	147,605
Secured Line of Credit, Net of Issuance Costs		113,785
Term Loans, Net	136,163
Capital Leases and Other Obligations	3,074	3,234
Total	$ 427,393	$ 264,624

Schedule of Income Tax Included

Schedule of Income Tax Included in Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Tax Benefit (Expense)		$ 393		$ (2,321)
Effective Tax Rate	(0.00%)	0.70%	(0.00%)	(2.20%)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Tax Disclosure [Line Items]
Estimated annual effective tax rate from continue operations	0.00%	(0.70%)	0.00%	2.20%
Statutory rate			35.00%
Estimated annual effective tax rate from continuing operations				(2.20%)
Valuation allowance for deferred tax assets	$ 0		$ 0
Income taxes benefit from continuing operations		$ (393,000)		$ 2,321,000
Income tax payments			2,000,000
Income tax refunds			200,000
Senior Notes
Income Tax Disclosure [Line Items]
Cancellation of debt income			$ 543,200,000

Capital Stock - Additional Info

Capital Stock - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	May 12, 2017	May 31, 2017	Mar. 31, 2016	Jun. 30, 2017	Jun. 30, 2016	May 05, 2017	Mar. 31, 2017	Dec. 31, 2016	May 27, 2016
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized			100,000,000	100,000,000		100,000,000		100,000,000	200,000,000
Preferred Stock, shares authorized				100,000				100,000
Common Stock, shares issued	9,900,000			9,952,861			99,000,000	9,787,146
Common Stock, shares outstanding				9,952,861				9,787,146
Issuance of common stock				100,000
Reverse stock split				On May 5, 2017, the Company’s common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017.
Effective date of reverse stock split occurred				May 12, 2017
Preferred Stock, par value				$ 0.001				$ 0.001
Preferred Stock, shares issued				3,987				3,987
Preferred Stock, shares outstanding				3,987				3,987
Preferred stock shares converted			10,100,000
Common Stock
Schedule Of Capitalization Equity [Line Items]
Reverse stock split	one-for-ten
Preferred stock convertible preferred stock					900,000
6.0% convertible perpetual preferred stock, Series A
Schedule Of Capitalization Equity [Line Items]
Preferred Stock, par value				$ 0.001				$ 0.001
Preferred Stock, shares issued				3,987				3,987
Preferred Stock, shares outstanding				3,987				3,987
Preferred stock shares converted					12,013
Dividend per share in amount				$ 600
Dividend per share percentage				6.00%
Cash dividend paid per share		$ 150
Aggregate amount of cash dividend paid		$ 0.6
Accumulated dividends in arrears				$ 3
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Liquidation preference per share				$ 10,000

Employee Benefit and Equity P60

Employee Benefit and Equity Plans - Additional Information (Details)	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)shares	Jun. 30, 2017USD ($)Person$ / sharesshares	Jun. 30, 2016USD ($)EmployeesPersonshares	Dec. 31, 2015$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of option issued to purchase common stock | shares				0	88,892
Stock-based compensation expense				$ 571,000	$ 1,305,000
Stock options exercised | shares				0
Tax benefit related to stock option exercises				$ 0	$ 0
Outstanding weighted average remaining term (in years)				4 years 6 months
Weighted average remaining term of options exercisable (in years)				3 years 2 months 12 days
Aggregate intrinsic value of options outstanding	$ 0			$ 0
Aggregate intrinsic value of options exercisable	0			0
Unrecognized compensation expense	200,000			200,000
Restricted Stock or Unit Expense	100,000		$ 200,000
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of employees | Employees					34
Stock-based compensation expense	100,000	$ 100,000		200,000	$ 100,000
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	400,000	$ 1,100,000		400,000	$ 900,000
Unrecognized compensation expense	$ 1,100,000			$ 1,100,000
Common stock issued by compensation committee | shares				101,237	42,883
Number of employees subjected to issuance of common stock | Person				28	25
Fair value of TSR awards of per share estimated on date of grant | $ / shares				$ 5.18
Unrecognized compensation expense weighted average period, in years				1 year 7 months 6 days
Vested stock | shares				39,278
Restricted Stock | TSR
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				$ 0		$ 2.56
Restricted Stock | Certain Performance Factors Waived
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested stock | shares			23,557	17,952

Summary of Issued and Outstandi

Summary of Issued and Outstanding Stock Options (Details)	Jun. 30, 2017$ / sharesshares
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding | shares	112,348
Weighted-Average Exercise Price, Outstanding	$ 39.91
Number Exercisable | shares	52,955
Weighted-Average Exercise Price, Exercisable	$ 62.16
Exercise Price Range 9.70
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.70
Number Outstanding | shares	2,750
Weighted-Average Exercise Price, Outstanding	$ 9.70
Number Exercisable | shares	918
Weighted-Average Exercise Price, Exercisable	$ 9.70
Exercise Price Range 16.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 16.90
Number Outstanding | shares	75,352
Weighted-Average Exercise Price, Outstanding	$ 16.90
Number Exercisable | shares	25,125
Weighted-Average Exercise Price, Exercisable	$ 16.90
Exercise Price Range 40.50
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 40.50
Number Outstanding | shares	4,000
Weighted-Average Exercise Price, Outstanding	$ 40.50
Weighted-Average Exercise Price, Exercisable	40.50
Exercise Price Range 49.00
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 49
Number Outstanding | shares	4,000
Weighted-Average Exercise Price, Outstanding	$ 49
Number Exercisable | shares	666
Weighted-Average Exercise Price, Exercisable	$ 49
Exercise Price Range 50.40
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 50.40
Number Outstanding | shares	3,070
Weighted-Average Exercise Price, Outstanding	$ 50.40
Number Exercisable | shares	3,070
Weighted-Average Exercise Price, Exercisable	$ 50.40
Exercise Price Range 95.00
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 95
Number Outstanding | shares	5,000
Weighted-Average Exercise Price, Outstanding	$ 95
Number Exercisable | shares	5,000
Weighted-Average Exercise Price, Exercisable	$ 95
Exercise Price Range 99.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 99.90
Number Outstanding | shares	12,959
Weighted-Average Exercise Price, Outstanding	$ 99.90
Number Exercisable | shares	12,959
Weighted-Average Exercise Price, Exercisable	$ 99.90
Exercise Price Range 104.20
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 104.20
Number Outstanding | shares	2,217
Weighted-Average Exercise Price, Outstanding	$ 104.20
Number Exercisable | shares	2,217
Weighted-Average Exercise Price, Exercisable	$ 104.20
Exercise Price Range 223.40
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 223.40
Number Outstanding | shares	3,000
Weighted-Average Exercise Price, Outstanding	$ 223.40
Number Exercisable | shares	3,000
Weighted-Average Exercise Price, Exercisable	$ 223.40

Monte Carlo Simulation Model As

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

Summary of Nonvested Stock Acti

Summary of Nonvested Stock Activity (Details) - Restricted Stock - $ / shares	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	242,824
Awards, Number of Shares	101,237	42,883
Forfeitures, Number of Shares	(19,185)
Vested, Number of Shares	(39,278)
Stock awards, ending balance, Number of Shares	285,598
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 26.34
Awards, Weighted Average Grant Date Fair Value	5.18
Forfeitures, Weighted Average Grant Date Fair Value	86.78
Vested, Weighted Average Grant Date Fair Value	22.18
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 15.35

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2017USD ($)Rigs	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)Rigs	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)
Loss Contingencies [Line Items]
Significant probable or possible environmental contingent liabilities	$ 0		$ 0
Letters of credit	46,300,000		46,300,000
Rent expense	200,000	$ 300,000	500,000	$ 600,000
Maximum guarantee of payment of obligations	391,500,000		$ 391,500,000
Guarantee obligations period			2,029
Transportation, processing and marketing expenses of natural gas, condensate and natural gas liquids	26,400,000	21,800,000	$ 52,700,000	43,300,000
Fees related to unutilized capacity commitments	700,000	700,000	1,400,000	1,000,000
Production and Lease Operating Expense	29,374,000	25,221,000	58,308,000	49,672,000
Accrued Liabilities	$ 32,791,000		$ 32,791,000		$ 37,207,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest	51.00%		51.00%
Charges incurred for unutilized processing capacity	$ 1,700,000	800,000	$ 3,300,000	1,400,000
Capacity Reservation | 2017
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	9,100,000		9,100,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	15,900,000		15,900,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	15,900,000		15,900,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	15,900,000		15,900,000
Capacity Reservation | 2021
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	15,900,000		15,900,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed	$ 78,300,000		$ 78,300,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations | Rigs	1		1
Drilling Commitments | 2017
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs			$ 1,400,000
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	$ 800,000	$ 800,000	$ 1,600,000	$ 1,300,000
Accrued Liabilities	$ 1,600,000		$ 1,600,000

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Details) $ in Thousands	Jun. 30, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 505
2,018	565
2,019	563
2,020	422
Total	$ 2,055

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands	Jun. 30, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 22,281
2,018	46,241
2,019	46,408
2,020	45,123
2,021	42,204
Thereafter	464,028
Total	$ 666,285

Fee for Unconventional Gas Well

Fee for Unconventional Gas Wells (Details) - Pennsylvania Impact Fee	6 Months Ended
	Jun. 30, 2017USD ($)	[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 fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

Earnings Per Common Share - Add

Earnings Per Common Share - Additional Information (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
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	221,502	713,117	221,502	227,057
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	112,348	130,447	112,348	130,447
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	43,124	71,715	43,124	71,715

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

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Jun. 30, 2015
Schedule Of Equity Method Investments [Line Items]
Equity Method Investments						$ 0
Production and Lease Operating Expense	$ 29,374,000	$ 25,221,000	$ 58,308,000	$ 49,672,000
RW Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%		40.00%
Contributions to Equity Method Investments			$ 0	0
Loss on Equity Method Investments	$ (500,000)	(500,000)	(1,000,000)	(1,000,000)
Production and Lease Operating Expense	100,000	$ 300,000	100,000	$ 300,000
Receivables	0		0		$ 0
Payables	$ 0		$ 0		$ 0

Impairment Expense - Additional

Impairment Expense - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$ 3,032	$ 25,139	$ 4,577	$ 35,780
Butler County, Pennsylvania, and Warrior County, Ohio
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			3,800
Butler County, Pennsylvania, and Warrior County, Ohio | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense				$ 34,800
Butler County | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			800
Marcellus and Utica Shale
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Undeveloped properties, cost	$ 205,700		$ 205,700

Exploration Expense - Additiona

Exploration Expense - Additional Information (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)Well
Exploration Expense [Line Items]
Exploration Expense	$ 99	$ 803	$ 319	$ 1,738
Geological and Geophysical Type Expenditures
Exploration Expense [Line Items]
Exploration Expense			200	900
Dry Hole Expense For Non Operated Properties
Exploration Expense [Line Items]
Exploration Expense				$ 800
Number of exploratory wells | Well				2
Delay Rentals for Non Operated Properties
Exploration Expense [Line Items]
Exploration Expense			$ 100

Condensed Consolidating Finan73

Condensed Consolidating Financial Information - Additional Information (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Principal amount	$ 600.3	$ 601.2

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Current Assets
Cash and Cash Equivalents	$ 12,855	$ 3,697	$ 3,438
Accounts Receivable	23,762	25,448
Taxes Receivable	48	211
Short-Term Derivative Instruments	7,317	1,873
Inventory, Prepaid Expenses and Other	2,002	2,546
Total Current Assets	45,984	33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	977,665	1,053,461
Unevaluated Oil and Gas Properties	205,691	215,794
Other Property and Equipment	22,309	21,401
Wells and Facilities in Progress	59,807	21,964
Pipelines	21,289	18,029
Total Property and Equipment	1,286,761	1,330,649
Less: Accumulated Depreciation, Depletion and Amortization	(434,483)	(475,205)
Net Property and Equipment	852,278	855,444
Other Assets	2,488	2,492
Long-Term Derivative Instruments	4,820	2,212
Total Assets	905,570	893,923
Current Liabilities
Accounts Payable	46,235	40,712
Current Maturities of Long-Term Debt	834	764
Accrued Liabilities	32,791	37,207
Short-Term Derivative Instruments	6,563	25,025
Total Current Liabilities	86,423	103,708
Long-Term Derivative Instruments	9,450	7,227
Other Long-Term Debt	3,627	3,409
Other Deposits and Liabilities	7,731	8,671
Future Abandonment Cost	9,658	8,736
Total Liabilities	901,872	883,697
Stockholders’ Equity
Preferred Stock	1	1
Common Stock	10	10
Additional Paid-In Capital	651,659	650,669
Accumulated Deficit	(647,972)	(640,454)
Total Stockholders’ Equity	3,698	10,226
Total Liabilities and Stockholders’ Equity	905,570	893,923
Eliminations
Property and Equipment (Successful Efforts Method)
Intercompany Receivables	(1,037,626)	(1,035,713)
Investment in Subsidiaries – Net	274,746	130,362
Total Assets	(762,880)	(905,351)
Current Liabilities
Intercompany Payables	(1,037,626)	(1,035,713)
Total Liabilities	(1,037,626)	(1,035,713)
Stockholders’ Equity
Additional Paid-In Capital	(177,144)	(177,144)
Accumulated Deficit	451,890	307,506
Total Stockholders’ Equity	274,746	130,362
Total Liabilities and Stockholders’ Equity	(762,880)	(905,351)
Senior Secured Line of Credit, Net
Current Liabilities
Senior Secured Line of Credit, Term Loans and Senior Notes, Net		113,785
Term Loans, Net
Current Liabilities
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	136,163
Senior Notes, Net
Current Liabilities
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	648,820	638,161
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents	7,951	3,694
Accounts Receivable	23,755	22,609
Short-Term Derivative Instruments	6,982	650
Inventory, Prepaid Expenses and Other	1,392	2,521
Total Current Assets	40,080	29,474
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	977,665	1,053,461
Unevaluated Oil and Gas Properties	205,691	215,794
Other Property and Equipment	22,309	21,401
Wells and Facilities in Progress	59,807	21,964
Pipelines	21,289	18,029
Total Property and Equipment	1,286,761	1,330,649
Less: Accumulated Depreciation, Depletion and Amortization	(434,483)	(475,205)
Net Property and Equipment	852,278	855,444
Other Assets	2,488	2,492
Investment in Subsidiaries – Net	(2,484)	(2,388)
Long-Term Derivative Instruments	4,111	500
Total Assets	896,473	885,522
Current Liabilities
Accounts Payable	46,235	40,712
Current Maturities of Long-Term Debt	834	764
Accrued Liabilities	30,025	32,328
Short-Term Derivative Instruments	6,563	25,025
Total Current Liabilities	83,657	98,829
Long-Term Derivative Instruments	9,450	7,227
Other Long-Term Debt	3,627	3,409
Other Deposits and Liabilities	7,731	8,671
Future Abandonment Cost	9,658	8,736
Intercompany Payables	1,033,962	1,032,050
Total Liabilities	1,148,085	1,158,922
Stockholders’ Equity
Additional Paid-In Capital	177,144	177,144
Accumulated Deficit	(428,756)	(450,544)
Total Stockholders’ Equity	(251,612)	(273,400)
Total Liabilities and Stockholders’ Equity	896,473	885,522
Non-Guarantor Subsidiaries
Current Liabilities
Accrued Liabilities	421	421
Total Current Liabilities	421	421
Intercompany Payables	3,664	3,663
Total Liabilities	4,085	4,084
Stockholders’ Equity
Accumulated Deficit	(4,085)	(4,084)
Total Stockholders’ Equity	(4,085)	(4,084)
Parent Company
Current Assets
Cash and Cash Equivalents	4,904	3
Accounts Receivable	7	2,839
Taxes Receivable	48	211
Short-Term Derivative Instruments	335	1,223
Inventory, Prepaid Expenses and Other	610	25
Total Current Assets	5,904	4,301
Property and Equipment (Successful Efforts Method)
Intercompany Receivables	1,037,626	1,035,713
Investment in Subsidiaries – Net	(272,262)	(127,974)
Long-Term Derivative Instruments	709	1,712
Total Assets	771,977	913,752
Current Liabilities
Accrued Liabilities	2,345	4,458
Total Current Liabilities	2,345	4,458
Total Liabilities	787,328	756,404
Stockholders’ Equity
Preferred Stock	1	1
Common Stock	10	10
Additional Paid-In Capital	651,659	650,669
Accumulated Deficit	(667,021)	(493,332)
Total Stockholders’ Equity	(15,351)	157,348
Total Liabilities and Stockholders’ Equity	771,977	913,752
Parent Company | Senior Secured Line of Credit, Net
Current Liabilities
Senior Secured Line of Credit, Term Loans and Senior Notes, Net		113,785
Parent Company | Term Loans, Net
Current Liabilities
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	136,163
Parent Company | Senior Notes, Net
Current Liabilities
Senior Secured Line of Credit, Term Loans and Senior Notes, Net	$ 648,820	$ 638,161

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$ 47,457	$ 31,271	$ 99,522	$ 56,944
Other Operating Revenue (Expense)	5	(6)	11	7
TOTAL OPERATING REVENUE	47,462	31,265	99,533	56,951
OPERATING EXPENSES
Production and Lease Operating Expense	29,374	25,221	58,308	49,672
General and Administrative Expense	4,294	4,837	8,828	10,121
(Gain) Loss on Disposal of Assets	(124)	(4,307)	(1,959)	(4,295)
Impairment Expense	3,032	25,139	4,577	35,780
Exploration Expense	99	803	319	1,738
Depreciation, Depletion, Amortization and Accretion	15,501	14,750	30,969	31,262
Other Operating (Income) Expense	(98)	704	(118)	1,030
TOTAL OPERATING EXPENSES	52,078	67,147	100,924	125,308
LOSS FROM OPERATIONS	(4,616)	(35,882)	(1,391)	(68,357)
OTHER INCOME (EXPENSE)
Interest Expense	(12,122)	(11,439)	(21,266)	(24,469)
Gain (Loss) on Derivatives, Net	10,386	(29,169)	18,766	(25,120)
Other Income (Expense)	20	12	(7)	12
(Loss) Gain on Extinguishments of Debt	(3,271)	23,707	(3,022)	23,707
Debt Exchange Expense		(533)		(9,014)
TOTAL OTHER INCOME (EXPENSE)	(4,987)	(17,422)	(5,529)	(34,884)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(9,603)	(53,304)	(6,920)	(103,241)
Income Tax Benefit (Expense)		393		(2,321)
NET LOSS FROM CONTINUING OPERATIONS	(9,603)	(52,911)	(6,920)	(105,562)
Loss From Discontinued Operations, Net of Income Taxes		(1,683)		(9,173)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	(9,603)	(54,594)	(6,920)	(114,735)
Preferred Stock Dividends	(598)	(1,723)	(1,196)	(3,828)
Effect of Preferred Stock Conversions		72,316		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(10,201)	15,999	(8,116)	(46,247)
Eliminations
OTHER INCOME (EXPENSE)
(Loss) Income From Equity in Consolidated Subsidiaries	(6,345)	65,341	(19,047)	104,226
TOTAL OTHER INCOME (EXPENSE)	(6,345)	65,341	(19,047)	104,226
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(6,345)	65,341	(19,047)	104,226
NET LOSS FROM CONTINUING OPERATIONS		65,341	(19,047)	104,226
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	(6,345)	65,341	(19,047)	104,226
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(6,345)	65,341	(19,047)	104,226
Guarantor Subsidiaries
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	47,457	31,271	99,522	56,944
Other Operating Revenue (Expense)	5	(6)	11	7
TOTAL OPERATING REVENUE	47,462	31,265	99,533	56,951
OPERATING EXPENSES
Production and Lease Operating Expense	29,374	25,221	58,308	49,671
General and Administrative Expense	3,771	3,661	8,232	9,080
(Gain) Loss on Disposal of Assets	(124)	(4,307)	(1,959)	(4,295)
Impairment Expense	3,032	25,139	4,577	35,780
Exploration Expense	99	803	319	1,737
Depreciation, Depletion, Amortization and Accretion	15,501	14,747	30,969	31,249
Other Operating (Income) Expense	(99)	704	(119)	1,030
TOTAL OPERATING EXPENSES	51,554	65,968	100,327	124,252
LOSS FROM OPERATIONS	(4,092)	(34,703)	(794)	(67,301)
OTHER INCOME (EXPENSE)
Interest Expense	(442)	(269)	(809)	(539)
Gain (Loss) on Derivatives, Net	10,861	(29,169)	20,659	(25,120)
Other Income (Expense)	20	12	(7)	12
(Loss) Income From Equity in Consolidated Subsidiaries	(1)	(54)	(1)	79
TOTAL OTHER INCOME (EXPENSE)	10,438	(29,480)	19,842	(25,568)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	6,346	(64,183)	19,048	(92,869)
Income Tax Benefit (Expense)		473		(2,090)
NET LOSS FROM CONTINUING OPERATIONS		(63,710)	19,048	(94,959)
Loss From Discontinued Operations, Net of Income Taxes		(1,629)		(9,106)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	6,346	(65,339)	19,048	(104,065)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	6,346	(65,339)	19,048	(104,065)
Non-Guarantor Subsidiaries
OPERATING EXPENSES
Production and Lease Operating Expense				1
Exploration Expense				1
Depreciation, Depletion, Amortization and Accretion		3		13
Other Operating (Income) Expense	1		1
TOTAL OPERATING EXPENSES	1	3	1	15
LOSS FROM OPERATIONS	(1)	(3)	(1)	(15)
OTHER INCOME (EXPENSE)
(Loss) Income From Equity in Consolidated Subsidiaries		54		(79)
TOTAL OTHER INCOME (EXPENSE)		54		(79)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(1)	51	(1)	(94)
NET LOSS FROM CONTINUING OPERATIONS		51	(1)	(94)
Loss From Discontinued Operations, Net of Income Taxes		(54)		(67)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	(1)	(3)	(1)	(161)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(1)	(3)	(1)	(161)
Parent Company
OPERATING EXPENSES
General and Administrative Expense	523	1,176	596	1,041
TOTAL OPERATING EXPENSES	523	1,176	596	1,041
LOSS FROM OPERATIONS	(523)	(1,176)	(596)	(1,041)
OTHER INCOME (EXPENSE)
Interest Expense	(11,680)	(11,170)	(20,457)	(23,930)
Gain (Loss) on Derivatives, Net	(475)		(1,893)
(Loss) Gain on Extinguishments of Debt	(3,271)	23,707	(3,022)	23,707
(Loss) Income From Equity in Consolidated Subsidiaries	6,346	(65,341)	19,048	(104,226)
Debt Exchange Expense		(533)		(9,014)
TOTAL OTHER INCOME (EXPENSE)	(9,080)	(53,337)	(6,324)	(113,463)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(9,603)	(54,513)	(6,920)	(114,504)
Income Tax Benefit (Expense)		(80)		(231)
NET LOSS FROM CONTINUING OPERATIONS		(54,593)	(6,920)	(114,735)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	(9,603)	(54,593)	(6,920)	(114,735)
Preferred Stock Dividends	(598)	(1,723)	(1,196)	(3,828)
Effect of Preferred Stock Conversions		72,316		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (10,201)	$ 16,000	$ (8,116)	$ (46,247)

Condensed Consolidating State76

Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ (9,603)	$ (54,594)	$ (6,920)	$ (114,735)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion			30,969	36,345
(Gain) Loss on Derivatives	(10,386)	29,169	(18,766)	25,120
Cash Settlements of Derivatives			(5,525)	30,340
Dry Hole Expense				870
Non-cash Dry Hole Expense			13	870
Equity-based Compensation Expense			571	1,305
Gain on Disposal of Assets			(1,959)	(4,338)
Amortization of net Bond Discount and Deferred Debt Issuance Costs				538
Non-cash Interest Expense related to Debt Restructurings and Exchanges			12,431	8,126
Loss (Gain) on Extinguishments of Debt			3,022	(23,757)
Impairment Expense			4,577	39,323
Other Non-cash (Income) Expense			41	131
Changes in operating assets and liabilities
Accounts Receivable			7,229	(14,772)
Taxes Receivable			163
Inventory, Prepaid Expenses and Other Assets			52	1,118
Accounts Payable and Accrued Liabilities			(1,484)	10,425
Other Assets and Liabilities			(1,104)	(676)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			23,310	(4,637)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			24,513	190
Proceeds from Joint Venture				19,461
Acquisitions of Undeveloped Acreage			(1,783)	(5,900)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(54,004)	(37,738)
NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES			(31,274)	(23,987)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit			171,000	50,400
Repayments of Long-Term Debt and Line of Credit			(145,170)	(15,230)
Repayments of Loans and Other Notes Payable			(319)	(361)
Debt Issuance Costs			(7,791)	(3,838)
Payment of Preferred Dividends in Arrears			(598)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES			17,122	30,971
NET INCREASE IN CASH			9,158	2,347
CASH – BEGINNING			3,697	1,091	$ 1,091
CASH – ENDING	12,855	3,438	12,855	3,438	3,697
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)			(19,047)	104,226
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Impairment Expense				(39,323)
Changes in operating assets and liabilities
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			(19,047)	64,903
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			19,047	(64,903)
NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES			19,047	(64,903)
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)			19,048	(104,065)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion			30,969	36,293
(Gain) Loss on Derivatives	(10,861)	29,169	(20,659)	25,120
Cash Settlements of Derivatives			(5,525)	30,340
Dry Hole Expense				870
Non-cash Dry Hole Expense			13
Gain on Disposal of Assets			(1,959)	(4,338)
Impairment Expense			4,577	39,330
Other Non-cash (Income) Expense			41	(100)
Changes in operating assets and liabilities
Accounts Receivable			7,232	(14,452)
Inventory, Prepaid Expenses and Other Assets			638	1,093
Accounts Payable and Accrued Liabilities			(1,484)	15,148
Other Assets and Liabilities			(1,104)	(651)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			31,787	24,588
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			4,063	2,035
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			24,513	190
Proceeds from Joint Venture				19,461
Acquisitions of Undeveloped Acreage			(1,783)	(5,863)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(54,004)	(37,704)
NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES			(27,211)	(21,881)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable			(319)	(361)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES			(319)	(361)
NET INCREASE IN CASH			4,257	2,346
CASH – BEGINNING			3,694	1,089	1,089
CASH – ENDING	7,951	3,435	7,951	3,435	3,694
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)			(1)	(161)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion				52
Impairment Expense				(7)
Changes in operating assets and liabilities
Accounts Receivable				103
Other Assets and Liabilities				(25)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			(1)	(38)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			1	109
Acquisitions of Undeveloped Acreage				(37)
Capital Expenditures for Development of Oil & Gas Properties and Equipment				(34)
NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES			1	38
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)			(6,920)	(114,735)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
(Gain) Loss on Derivatives	475		1,893
Equity-based Compensation Expense			571	1,305
Amortization of net Bond Discount and Deferred Debt Issuance Costs				538
Non-cash Interest Expense related to Debt Restructurings and Exchanges			12,431	8,126
Loss (Gain) on Extinguishments of Debt			3,022	(23,757)
Impairment Expense				39,323
Other Non-cash (Income) Expense				231
Changes in operating assets and liabilities
Accounts Receivable			(3)	(423)
Taxes Receivable			163
Inventory, Prepaid Expenses and Other Assets			(586)	25
Accounts Payable and Accrued Liabilities				(4,723)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			10,571	(94,090)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			(23,111)	62,759
NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES			(23,111)	62,759
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit			171,000	50,400
Repayments of Long-Term Debt and Line of Credit			(145,170)	(15,230)
Debt Issuance Costs			(7,791)	(3,838)
Payment of Preferred Dividends in Arrears			(598)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES			17,441	31,332
NET INCREASE IN CASH			4,901	1
CASH – BEGINNING			3	2	2
CASH – ENDING	$ 4,904	$ 3	$ 4,904	$ 3	$ 3

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($)	Aug. 01, 2017	Jun. 30, 2017
Sale of Salineville Waterline
Subsequent Event [Line Items]
Purchase price of waterline		$ 7,000,000
Sale leaseback transaction, description		We intend to account for this transaction as a sale-leaseback arrangement and, pursuant to ASC 360, continue to hold this asset as held and used as of June 30, 2017.
Subsequent Event | BP
Subsequent Event [Line Items]
Reduction in transportation credit support obligation	$ 14,100,000
Subsequent Event | Secured Delayed Draw Term Loan Facility | BP
Subsequent Event [Line Items]
Available borrowing base	$ 14,100,000
Subsequent Event | Mt. Bellevue | BP
Subsequent Event [Line Items]
Product purchase agreement, period	4 years