Rex Energy 10-Q 10 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 05, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
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		99,024,707

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents		$ 5,075	$ 3,697
Accounts Receivable		25,264	25,448
Taxes Receivable		48	211
Short-Term Derivative Instruments		3,430	1,873
Inventory, Prepaid Expenses and Other		2,124	2,546
Total Current Assets		35,941	33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		963,481	1,053,461
Unevaluated Oil and Gas Properties		207,821	215,794
Other Property and Equipment		21,863	21,401
Wells and Facilities in Progress		40,740	21,964
Pipelines		21,262	18,029
Total Property and Equipment		1,255,167	1,330,649
Less: Accumulated Depreciation, Depletion and Amortization		(419,500)	(475,205)
Net Property and Equipment		835,667	855,444
Other Assets		2,495	2,492
Long-Term Derivative Instruments		3,292	2,212
Total Assets		877,395	893,923
Current Liabilities
Accounts Payable		36,838	40,712
Current Maturities of Long-Term Debt		801	764
Accrued Liabilities		31,922	37,207
Short-Term Derivative Instruments		12,801	25,025
Total Current Liabilities		82,362	103,708
Noncurrent Liabilities
Long-Term Derivative Instruments		10,265	7,227
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		106,573	113,785
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges	[1],[2]	650,758	641,762
Discount on Senior Notes, Net		(7,389)	(3,601)
Other Long-Term Debt		3,849	3,409
Other Deposits and Liabilities		8,262	8,671
Future Abandonment Cost		9,465	8,736
Total Liabilities		864,145	883,697
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock		1	1
Common Stock		96	95
Additional Paid-In Capital		650,924	650,584
Accumulated Deficit		(637,771)	(640,454)
Total Stockholders’ Equity		13,250	10,226
Total Liabilities and Stockholders’ Equity		$ 877,395	$ 893,923
[1]	Includes unamortized debt issuance costs of approximately ($17.3) million and ($7.9) million as of March 31, 2017 and December 31, 2016, respectively.
[2]	Includes unamortized deferred gain on debt exchange of approximately $32.8 million and $32.7 million as of March 31, 2017 and December 31, 2016, respectively, as a result of debt exchange transactions completed subsequent to the March 31, 2016 Exchange.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) (Unaudited) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Preferred Stock, par value	$ 0.001	$ 0.001
Preferred Stock, shares authorized	100,000	100,000
Preferred Stock, shares issued	3,987	3,987
Preferred Stock, shares outstanding	3,987	3,987
Common Stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	99,024,368	97,870,608
Common Stock, shares outstanding	99,024,368	97,870,608

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$ 52,065	$ 25,673
Other Operating Revenue	6	13
TOTAL OPERATING REVENUE	52,071	25,686
OPERATING EXPENSES
Production and Lease Operating Expense	28,934	24,451
General and Administrative Expense	4,534	5,284
(Gain) Loss on Disposal of Assets	(1,834)	11
Impairment Expense	1,546	10,641
Exploration Expense	220	936
Depreciation, Depletion, Amortization and Accretion	15,468	16,511
Other Operating (Income) Expense	(21)	327
TOTAL OPERATING EXPENSES	48,847	58,161
INCOME (LOSS) FROM OPERATIONS	3,224	(32,475)
OTHER INCOME (EXPENSE)
Interest Expense	(9,143)	(13,030)
Gain on Derivatives, Net	8,381	4,049
Other Expense	(28)
Debt Exchange Expense		(8,480)
Gain on Extinguishments of Debt	249
TOTAL OTHER EXPENSE	(541)	(17,461)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	2,683	(49,936)
Income Tax Expense		(2,715)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	2,683	(52,651)
Loss From Discontinued Operations, Net of Income Taxes		(7,490)
NET INCOME (LOSS)	2,683	(60,141)
Preferred Stock Dividends	(598)	(2,105)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 2,085	$ (62,246)
Earnings per common share:
Basic - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$ 0.02	$ (0.98)
Basic - Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders		(0.13)
Basic - Net Income (Loss) Attributable to Rex Energy Common Shareholders	$ 0.02	$ (1.11)
Basic - Weighted Average Shares of Common Stock Outstanding	97,687	56,003
Diluted - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$ 0.02	$ (0.98)
Diluted - Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders		(0.13)
Diluted - Net Income (Loss) Attributable to Rex Energy Common Shareholders	$ 0.02	$ (1.11)
Diluted - Weighted Average Shares of Common Stock Outstanding	97,687	56,003

Consolidated Statement of Chang

Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - 3 months ended Mar. 31, 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	$ 95	$ 1	$ 650,584	$ (640,454)
Balance (in shares) at Dec. 31, 2016		97,871	4
Non-Cash Compensation	60			60
Issuance of Common Stock for Debt Extinguishments	281	$ 1		280
Issuance of Common Stock for Debt Extinguishments (in shares)		333
Issuance of Restricted Stock, Net of Forfeitures (in shares)		820
Net Income	2,683				2,683
Balance at Mar. 31, 2017	$ 13,250	$ 96	$ 1	$ 650,924	$ (637,771)
Balance (in shares) at Mar. 31, 2017		99,024	4

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ 2,683	$ (60,141)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion	15,468	19,408
Gain on Derivatives	(8,381)	(4,049)
Cash Settlements of Derivatives	(3,443)	12,994
Equity-based Compensation Expense	71	(21)
Non-cash Exploration Expenses	11	843
Impairment Expense	1,546	14,184
Amortization of net Bond Discount and Deferred Debt Issuance Costs		547
Non-cash Interest Expense related to Debt Restructurings and Exchanges	6,081
Gain on Extinguishments of Debt	(249)
Gain on Sale of Assets	(1,834)	(30)
Other Non-cash Income	(66)	(29)
Deferred Income Tax Expense		2,092
Changes in operating assets and liabilities
Accounts Receivable	5,341	(4,873)
Inventory, Prepaid Expenses and Other Assets	422	660
Accounts Payable and Accrued Liabilities	(6,989)	(308)
Other Assets and Liabilities	(139)	(170)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	10,522	(18,893)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	24,329	71
Proceeds from Joint Venture for Reimbursement of Capital Costs		19,461
Acquisitions of Undeveloped Acreage	(299)	(5,266)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(25,476)	(15,068)
NET CASH USED IN INVESTING ACTIVITIES	(1,446)	(802)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit	21,500	46,500
Repayments of Long-Term Debt and Line of Credit	(28,500)
Repayments of Loans and Other Notes Payable	(131)	(184)
Debt Issuance Costs	(567)	(2,821)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(7,698)	43,495
NET INCREASE IN CASH	1,378	23,800
CASH – BEGINNING	3,697	1,091
CASH – ENDING	5,075	24,891
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	5,075	24,891
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	1,541	22,479
Cash Received for Income Taxes	(163)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations		566
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	(3,040)	2,830
Increase Long Term Debt - Equipment Financing	607
Increase in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions	5,208
Decrease in Bond Interest Payable due to Debt to Equity Conversions	(11)
Increase in Common Stock outstanding due to Debt to Equity Conversions	281	$ 6,476
Illinois Basin Operations
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin	$ (1,417)

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	3 Months Ended
	Mar. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent condensate, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in 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. 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	3 Months Ended
	Mar. 31, 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 $0.6 million and $0.2 million for the three months ended March 31, 2017 and 2016, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) March 31, 2017 Beginning Balance at January 1, 2017 $ 9,865 Future Abandonment Obligation Incurred $ 1,034 Future Abandonment Obligation Settled $ (112 ) Future Abandonment Obligation Cancelled or Sold $ (262 ) Future Abandonment Obligation Revision of Estimated Obligation $ 57 Future Abandonment Obligation Accretion Expense $ 570 Total Future Abandonment Cost 1 $ 11,152 1

Discontinued Operations_Assets

Discontinued Operations/Assets Held For Sale	3 Months Ended
	Mar. 31, 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 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 March 31, 2017, the first two 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 March 31, 2017, we have the potential to receive up to $8.1 million of additional proceeds, during the nine 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) 3/31/2017 $ 56.25 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays). Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day. The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations. As of March 31, 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 month period ended March 31, 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 month periods ended March 31, 2017 and 2016. For the Three Months Ended March 31, ($ in Thousands) 2017 2016 Revenues: Oil Sales $ — $ 4,821 Total Operating Revenue — 4,821 Costs and Expenses: Production and Lease Operating Expense — 5,698 General and Administrative Expense — 778 Gain on Disposal of Assets — (42 ) Impairment Expense — 3,543 Exploration Expense — 58 Depreciation, Depletion, Amortization and Accretion — 2,897 Interest Expense — 2 Other Income — (1 ) Total Costs and Expenses — 12,933 Loss From Discontinued Operations, Before Income Taxes — (8,112 ) Income Tax Benefit — 622 Loss From Discontinued Operations, Net of Taxes $ — $ (7,490 ) Production: Crude Oil (Bbls) — 158,304

Business and Oil and Gas Proper

Business and Oil and Gas Property Acquisitions and Dispositions	3 Months Ended
	Mar. 31, 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. Consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of March 31, 2017. BSP has paid approximately $86.7 million for its interest in elected wells as of March 31, 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 March 31, 2017, 30 of the 45 committed wells were in line and producing and 15 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 March 31, 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, that 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	3 Months Ended
	Mar. 31, 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	3 Months Ended
	Mar. 31, 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 and lenders in our Senior Credit Facility (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 three months ended March 31, 2017, approximately 95.8% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 51.0% 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	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	7. LONG-TERM DEBT Senior Credit Facility and Term Loan As of March 31, 2017, we maintained a revolving credit facility, evidenced by a credit agreement dated March 27, 2013 and most recently amended on April 28, 2017 (the “Senior Credit Facility”) with Royal Bank of Canada, as Administrative Agent and the lenders from time to time parties thereto. Borrowings under the Senior Credit Facility were limited by a borrowing base that was determined in regard to our oil and gas properties. As of March 31, 2017, we had $110.7 million borrowings outstanding, and approximately $46.3 million in outstanding undrawn letters of credit on our borrowing base of $190.0 million. We had $117.7 million borrowings outstanding as of December 31, 2016. On April 28, 2017, we entered a first lien delayed-draw term loan (the “Term Loan”) and subsequently terminated and repaid the amounts outstanding under the Senior Credit Facility (see Note 18, Subsequent Event The Term Loan requires we meet certain financial requirements, on a quarterly basis, including a maximum “Ratio of Net Senior Secured Debt to EBITDAX”, a minimum “Ratio of EBITDAX to Interest Expense” and a minimum “PDP Coverage Ratio” (all terms in quotations as defined in the Term Loan). EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, including our lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash or non-recurring activities. The Term Loan requires that as of the last day of any fiscal quarter, beginning with the quarter ending June 30, 2017, our “Ratio of Net Senior Secured Debt to EBITDAX” for the four fiscal quarters then ending to be greater than 3.25 to 1.00; provided that EBITDAX for the four fiscal quarters ending on June 30, 2017 shall be the EBITDAX for the two fiscal quarters then ending multiplied by two. In order to improve our liquidity positions to meet the financial requirements under our Term Loan and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, and/or other financing or strategic counterparties, which may include refinancing of existing debt, debt-for-debt or debt-for-equity exchanges, or other in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity will be raised from any such transactions or that any such transactions can or will be consummated within the period needed to meet our obligations. Senior Notes On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 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 three months ended March 31, 2017, we completed debt-for equity exchanges with certain holders of our Existing Notes. These exchanges resulted in the retirement of approximately $0.5 million of our remaining Existing Notes, in exchange for approximately 0.3 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the Company for the three months ended March 31, 2017 of approximately $0.2 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 March 31, 2017, our Fixed Charge Coverage Ratio was 1.26 to 1.00. We expect our Fixed Charge Coverage Ratio to improve based on our projections of decreased interest expense related to the New Notes. As of March 31, 2017, we were limited to incurring approximately $112.2 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 March 31, 2017 and December 31, 2016, we had recorded on our Consolidated Balance Sheets approximately $7.4 million and $3.6 million, respectively, of net discount related to the Senior Notes. The amortization of our net premium during the three months ended March 31, 2017, which follows the effective interest method, was approximately $3.8 million, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year. In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at March 31, 2017 and December 31, 2016: ($ in Thousands) March 31, 2017 (unaudited) December 31, 2016 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges (a)(c) $ 650,758 $ 641,762 Discount on Senior Notes, Net (7,389 ) (3,601 ) Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs (b)(d) 106,573 113,785 Capital Leases and Other Obligations (d) 4,650 4,173 Total Debt 754,592 756,119 Less Current Portion of Long-Term Debt (801 ) (764 ) Total Long-Term Debt $ 753,791 $ 755,355 (a) Includes unamortized debt issuance costs of approximately ($17.3) million and ($7.9) million as of March 31, 2017 and December 31, 2016, respectively. ( b ) Includes unamortized debt issuance costs of approximately $4.1 million and $3.9 million as of March 31, 2017 and December 31, 2016, respectively. (c) Includes unamortized deferred gain on debt exchange of approximately $32.8 million and $32.7 million as of March 31, 2017 and December 31, 2016, respectively, as a result of debt exchange transactions completed subsequent to the March 31, 2016 Exchange. (d) The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three months ended March 31, 2017 was approximately 3.7 %. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2017 was approximately 10.0%. The following is the principal maturity schedule for debt outstanding as of March 31, 2017: 2017 $ 587 2018 908 2019 111,746 2020 596,565 2021 802 Thereafter 5,364 Total (a) $ 715,972 (a) Excludes $7.4 million net discount on Senior Notes, $32.8 million of deferred gain on Senior Notes, and ($13.2) million of debt issuance costs

Derivative Instruments And Fair

Derivative Instruments And Fair Value Measurements	3 Months Ended
	Mar. 31, 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 March 31, 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 on Derivatives, Net. We enter into the majority of our derivative arrangements with five 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 on Derivatives, Net under Other Expense. We paid net cash settlements of $3.4 As of March 31, 2017, we had over 100.0% of our annualized condensate production hedged through the remainder of 2017, over 100.0% of our annualized natural gas production hedged through the remainder of 2017, and over 100.0% of our annualized NGL production hedged through the remainder of 2017. 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 Note3, 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 March 31, 2017, and December 31, 2016, we had $110.7 million and $117.7 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $600.7 million and $601.2 million, respectively, of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt As of March 31, 2017 and December 31, 2016, we did not have any interest rate derivatives outstanding. We utilize the mark-to-market accounting method to account for interest rate swap and swaptions. We recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Expense. The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016: For the Three Months Ended March 31, ($ in Thousands) 2017 2016 Oil $ 1,137 $ 325 Natural Gas (59 ) 5,363 NGLs 8,720 (1,621 ) Refined Products — (18 ) Contingent Consideration (1,417 ) — Gain on Derivatives, Net $ 8,381 $ 4,049 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 $16.3 million and approximately $28.2 million at March 31, 2017 and December 31, 2016, respectively. Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2017 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2017 - Swaps 81,000 Bbls $ — $ — $ — $ 53.00 $ 94 2017 - Deferred Put Spreads 15,000 Bbls 51.00 51.00 — — — 2017 - Collars 48,000 Bbls — 45.00 57.20 — — 2017 - Three-Way Collars 93,000 Bbls 40.16 49.68 61.50 — 108 2018 - Swaps 60,000 Bbls — — — 54.00 186 2018 - Collars 18,000 Bbls — 53.00 60.00 — — 2018 - Three-Way Collars 60,000 Bbls 43.00 52.00 62.30 — 92 375,000 Bbls $ 480 Natural Gas 2017 - Swaps 11,000,000 Mcf — — — 3.11 $ (1,332 ) 2017 - Swaptions 2,400,000 Mcf — — — 3.33 36 2017 - Cap Swaps 3,900,000 Mcf 2.35 — — 2.81 (1,591 ) 2017 - Collars 1,700,000 Mcf — 2.54 3.20 — (382 ) 2017 - Three-Way Collars 17,510,000 Mcf 2.33 3.01 3.87 — (133 ) 2017 - Calls 8,380,100 Mcf — — 4.51 — (338 ) 2017 - Basis Swaps - Dominion South 16,405,000 Mcf — — — (0.80 ) (2,467 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) 46 2018 - Swaps 12,585,000 Mcf — — — 3.14 289 2018 - Swaptions — Mcf — — — (200 ) 2018 - Three-Way Collars 8,775,000 Mcf 2.30 2.89 3.58 — (509 ) 2018 - Calls 16,489,900 Mcf — — 4.64 — (753 ) 2018 - Collars 450,000 Mcf — 3.20 3.65 — (33 ) 2018 - Basis Swaps - Dominion South 18,980,000 Mcf — — — (0.80 ) (3,417 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf (0.13 ) 62 2019 - Swaps 900,000 Mcf — — — 3.00 60 2019 - Basis Swaps - Dominion South 18,980,000 Mcf — — — (0.81 ) (3,190 ) 2020 - Basis Swaps - Dominion South 13,542,000 Mcf — — — (0.80 ) (1,551 ) 2021 - Basis Swaps - Dominion South 6,234,000 Mcf — — — (0.73 ) (461 ) 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (460 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (461 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (460 ) 198,381,000 Mcf $ (17,245 ) NGLs 2017 - C3+ NGL Swaps 1,689,000 Bbls — — — 0.71 $ (2,455 ) 2017 - Ethane Swaps 840,000 Bbls — — — 0.25 (237 ) 2018 - C3+ NGL Swaps 1,068,000 Bbls — — — 0.76 1,684 2018 - Ethane Swaps 660,000 Bbls — — — 0.31 (15 ) 2019 - Ethane Swaps 240,000 Bbls — — — 0.31 (75 ) 4,497,000 Bbls $ (1,098 ) The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016 is summarized below: March 31, December 31, ($ in Thousands) 2017 2016 Short-Term Derivative Assets: Crude Oil—Three-Way Collars 131 — Crude Oil—Swaps 175 — NGL—Swaps 1,291 — Natural Gas—Swaps 453 206 Natural Gas—Cap Swaps — 61 Natural Gas—Basis Swaps 132 232 Natural Gas—Three-Way Collars 523 151 Natural Gas—Swaption 170 — Contingent Consideration - Sale of Illinois Basin 555 1,223 Total Short-Term Derivative Assets $ 3,430 $ 1,873 Long-Term Derivative Assets: Crude Oil—Three-Way Collars $ 69 $ — Crude Oil—Swaps $ 143 NGL—Swaps 1,177 — Natural Gas—Swaps 707 206 Natural Gas—Basis Swaps 99 293 Natural Gas—Three-Way Collars 133 — Contingent Consideration - Sale of Illinois Basin 964 1,713 Total Long-Term Derivative Assets $ 3,292 $ 2,212 Total Derivative Assets $ 6,722 $ 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 (19 ) (220 ) NGL—Swaps (3,566 ) (9,895 ) Natural Gas—Three-Way Collars (889 ) (2,397 ) Natural Gas—Cap Swaps (1,591 ) (3,364 ) Natural Gas—Collars (415 ) (873 ) Natural Gas—Basis Swaps (3,561 ) (640 ) Natural Gas—Call (527 ) (1,478 ) Natural Gas—Swaption (184 ) (1,258 ) Natural Gas—Swaps (2,049 ) (4,673 ) Total Short - Term Derivative Liabilities $ (12,801 ) $ (25,025 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars (58 ) Crude Oil—Swaps (19 ) (146 ) NGL—Swaps — (2,200 ) Natural Gas—Swaps (94 ) (1,004 ) Natural Gas—Swaption (150 ) (167 ) Natural Gas—Basis Swaps (9,028 ) (1,260 ) Natural Gas—Collars — (115 ) Natural Gas—Call (565 ) (491 ) Natural Gas—Three-Way Collars (409 ) (1,786 ) Total Long-Term Derivative Liabilities $ (10,265 ) $ (7,227 ) Total Derivative Liabilities $ (23,066 ) $ (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 March 31, 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 March 31, 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 months ended March 31, 2017 and 2016, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at March 31, 2017 ($ in Thousands) Total Carrying Value as of March 31, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (16,344 ) $ — $ (16,344 ) $ — 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 March 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of March 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of March 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments. 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: March 31, 2017 December 31, 2016 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 650,758 $ 253,796 $ 641,762 $ 147,605 Secured Line of Credit, Net of Issuance Costs 106,573 106,573 113,785 113,785 Capital Leases and Other Obligations 4,650 3,129 4,173 3,234 Total $ 761,981 $ 363,498 $ 759,720 $ 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 three months ended March 31, 2017 and 2016, we recorded other than temporary impairments of $1.5 million and $10.6 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	3 Months Ended
	Mar. 31, 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 March 31, 2017 ($ in Thousands) 2017 2016 Income Tax Benefit $ — $ (2,715 ) Effective Tax Rate 0.0 % -5.4 % 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. As a result of having a full valuation allowance on deferred taxes on the Company’s entire operations, this approach results in a tax benefit being recorded in continuing operations to offset the tax charge on the gain recorded in discontinued operations. For the three months ended March 31, 2017, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 0.0% due to the recording of full valuation allowances against the tax benefits generated by pretax losses, resulting in recognition of no tax benefit for the period. 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. For the three months ended March 31, 2016, the estimated annual effective tax rate applied to ordinary losses from continuing operations was -5.4%. 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 three months ended March 31, 2017 and 2016 were negligible. Tax refunds received during the three months ended March 31, 2017 were approximately $0.2 million, and refunds received during the three months ended March 31, 2016 were negligible.

Capital Stock

Capital Stock	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Capital Stock	10. CAPITAL STOCK 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. As of March 31, 2017, we have authorized capital stock of 200,000,000 shares of common stock and 100,000 shares of preferred stock. As of March 31, 2017 and December 31, 2016, shares of common stock issued and outstanding totaled 99,024,368 and 97,870,608, respectively. During the three months ended March 31, 2017, we issued approximately 0.3 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 March 31, 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 and 3,987, respectively. During the three months ended March 31, 2016, 3,264 shares of Series A Preferred Stock were converted into approximately 1.8 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. No dividend was declared by our board of directors in 2016. As of March 31, 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 are 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	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2017, no new options to purchase shares of our common stock were granted. During the three months ended March 31, 2016, we issued 851,422 options to purchase shares of our common stock to 29 employees. Stock-based compensation expense from continuing operations relating to stock options outstanding for the three months ended March 31, 2017 was $0.1 million. Stock-based compensation expense from continuing operations relating to stock options outstanding for the three months ended March 31, 2016 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. There were no stock options exercised during the three months ended March 31, 2017. There was no tax benefit related to stock option exercises for each of the three-month periods ended March 31, 2017 and 2016. A summary of the status of our issued and outstanding stock options as of March 31, 2017 is as follows: Outstanding Exercisable Exercise Price Number Outstanding at March 31, 2017 Weighted-Average Exercise Price Number Exercisable at March 31, 2017 Weighted-Average Exercise Price $ 0.97 27,500 $ 0.97 — $ 0.97 $ 1.69 753,428 $ 1.69 251,135 $ 1.69 $ 4.05 40,000 $ 4.05 — $ 4.05 $ 4.90 40,000 $ 4.90 6,666 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,171,100 $ 4.16 567,973 $ 6.47 The weighted average remaining contractual term for options outstanding at March 31, 2017 was 4.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at March 31, 2017 was 3.2 years and there was no aggregate intrinsic value. As of March 31, 2017, unrecognized compensation expense related to stock options was $0.2 million. Restricted Stock Awards During the three-month period ended March 31, 2017, the Compensation Committee approved the issuance of an aggregate of 1,012,242 shares of restricted common stock to 28 employees. During the three-month period ended March 31, 2016, the Compensation Committee approved the issuance of an aggregate of 420,901 shares of restricted stock to 22 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 three months ended March 31, 2017, 179,519 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.1 million for the quarter. Compensation expense from restricted stock awards associated with our continuing operations totaled $0.9 million and $1.8 million for the three months ended March 31, 2017 and 2016, respectively. During the first quarter of 2016, 235,573 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 March 31, 2017, total unrecognized compensation cost related to restricted common stock grants was approximately $1.4 million, which will be recognized over a weighted average period of 1.6 years. A summary of the restricted stock activity for the three months ended March 31, 2017 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2016 2,427,494 $ 2.63 Awards 1,012,242 0.52 Forfeitures (191,353 ) 8.69 Vested (384,236 ) 2.13 Restricted stock awards, as of March 31, 2017 2,864,147 $ 1.55

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 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. Other than as set forth below, there have been 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. In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 2013, the Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings. In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated. In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case. In July 2015, the trial court denied plaintiffs’ motion for class certification. Plaintiffs appealed the denial of class certification in September 2015. In June 2016, the parties each presented arguments on the appeal before a three-judge panel of the Pennsylvania Superior Court (the “Superior Court”). In January 2017, the three-judge panel vacated the trial court’s denial of class certification and remanded the case to the trial court. We promptly applied for reconsideration or reargument with the entire Superior Court ( en banc We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any. Environmental Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of March 31, 2017, we know of no significant probable or possible environmental contingent liabilities. Letters of Credit As of March 31, 2017, we have posted $46.3 million in various letters of credit to secure our drilling and related operations. Lease Commitments As of March 31, 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 months ended March 31, 2017 and 2016, was approximately $0.2 million and $0.3 million, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2017 $ 749 2018 565 2019 563 2020 422 2021 — Thereafter — Total $ 2,299 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 $14.1 million in 2017, $16.3 million in 2018, $16.3 million in 2019, $16.4 million in 2020, $16.3 million in 2021 and $80.4 million thereafter, assuming our average net revenue interest in the region of approximately 52%. Charges incurred for unutilized processing capacity with MarkWest during the three months ended March 31, 2017 and 2016 were $1.6 million and $0.6 million, 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 $2.1 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. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $0.5 million in 2017, 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 $396.7 million through 2029. For the three months ended March 31, 2017 and 2016, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $26.3 million and $21.5 million, 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 months ended March 31, 2017 and 2016, we incurred approximately $0.7 million and $0.4 million, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) 2017 $ 32,822 2018 47,350 2019 47,522 2020 46,226 2021 43,285 Thereafter 479,768 Total $ 696,973 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 months ended March 31, 2017 and 2016, we recorded expense of approximately $0.8 million and $0.5 million, respectively.

Earnings Per Common Share

Earnings Per Common Share	3 Months Ended
	Mar. 31, 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 months ended March 31, 2017,, we excluded stock options to purchase 1.2 million 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 months ended March 31, 2016, we excluded stock options to purchase 1.3 million shares of our common stock, due to our Net Loss from Continuing Operations. For the three months ended March 31, 2017 and 2016, we excluded performance-based restricted stock of 0.4 million shares and 0.7 million 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 March 31, Numerator: 2017 2016 Net Income (Loss) From Continuing Operations $ 2,683 $ (52,651 ) Net Loss From Discontinued Operations — (7,490 ) Less: Preferred Stock Dividends (598 ) (2,105 ) Net Income (Loss) Attributable to Common Shareholders $ 2,085 $ (62,246 ) Denominator: Weighted Average Common Shares Outstanding - Basic 97,687 56,003 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 97,687 56,003 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Income (Loss) From Continuing Operations $ 0.02 $ (0.98 ) — Net Loss From Discontinued Operations — (0.13 ) — Net Income (Loss) Attributable to Common Shareholders $ 0.02 $ (1.11 ) Diluted — Net Income (Loss) From Discontinued Operations $ 0.02 $ (0.98 ) — Net Loss From Discontinued Operations — (0.13 ) — Net Income (Loss) Attributable to Common Shareholders $ 0.02 $ (1.11 )

Equity Method Investments

Equity Method Investments	3 Months Ended
	Mar. 31, 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 three months of 2017 and 2016. RW Gathering recorded net losses from continuing operations of $0.5 million during each of the three months ended March 31, 2017 and 2016. 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 months ended March 31, 2017 and 2016, we incurred approximately $0.2 million in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of March 31, 2017 and December 31, 2016, there were no receivables or payables due between RW Gathering and us.

Impairment Expense

Impairment Expense	3 Months Ended
	Mar. 31, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment Expense	15. IMPAIRMENT EXPENSE For the three months ended March 31, 2017 and 2016, impairment expenses for continuing operations incurred were approximately $1.5 million and $10.6 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 three months ended March 31, 2017 included approximately $0.8 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 $0.7 million during the first three months of 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 our incurrence of additional impairment expense. As of March 31, 2017, we continued to carry the costs of undeveloped properties of approximately $207.8 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we have development, trade or lease extension plans. The expense incurred during the first three months of 2016 included proved properties of approximately $10.6 million in impairment related to 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.

Exploration Expense

Exploration Expense	3 Months Ended
	Mar. 31, 2017
Extractive Industries [Abstract]
Exploration Expense	16. EXPLORATION EXPENSE For the three months ended March 31, 2017 and 2016, exploration expenses for continuing operations incurred were approximately $0.2 million and $0.9 million, respectively. Approximately $0.1 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 $0.1 million was due to geological and geophysical type expenditures.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	3 Months Ended
	Mar. 31, 2017
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of March 31, 2017, we had $600.7 million aggregate principal amount of outstanding Senior Notes, as shown in Note 7, Long-Term Debt • Rex Energy I, LLC • Rex Energy Operating Corporation • Rex Energy IV, LLC • PennTex Resources Illinois, Inc. • R.E. Gas Development, LLC The non-guarantor subsidiaries include certain consolidated subsidiaries, including R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of March 31, 2017, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of March 31, 2017 and December 31, 2016, the condensed consolidating statements of operations for the three-month periods ended March 31, 2017 and 2016, and the condensed consolidating statements of cash flows for the three-month periods ended March 31, 2017 and 2016. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF MARCH 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non- Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 5,072 $ — $ 3 $ — $ 5,075 Accounts Receivable 25,264 — — — 25,264 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 2,875 — 555 — 3,430 Inventory, Prepaid Expenses and Other 2,112 — 12 — 2,124 Total Current Assets 35,323 — 618 — 35,941 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 963,481 — — — 963,481 Unevaluated Oil and Gas Properties 207,821 — — — 207,821 Other Property and Equipment 21,863 — — — 21,863 Wells and Facilities in Progress 40,740 — — — 40,740 Pipelines 21,262 — — — 21,262 Total Property and Equipment 1,255,167 — — — 1,255,167 Less: Accumulated Depreciation, Depletion and Amortization (419,500 ) — — — (419,500 ) Net Property and Equipment 835,667 — — — 835,667 Other Assets 2,495 — — — 2,495 Intercompany Receivables — — 1,027,360 (1,027,360 ) — Investment in Subsidiaries – Net (2,484 ) — (272,261 ) 274,745 — Long-Term Derivative Instruments 2,329 — 963 — 3,292 Total Assets $ 873,330 $ — $ 756,680 $ (752,615 ) $ 877,395 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 36,838 $ — $ — $ — $ 36,838 Current Maturities of Long-Term Debt 801 — — — 801 Accrued Liabilities 25,311 421 6,190 — 31,922 Short-Term Derivative Instruments 12,801 — — — 12,801 Total Current Liabilities 75,751 421 6,190 — 82,362 Long-Term Derivative Instruments 10,265 — — — 10,265 Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs — — 106,573 — 106,573 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges — — 650,758 — 650,758 Discount on Senior Notes, Net — — (7,389 ) — (7,389 ) Other Long-Term Debt 3,849 — — — 3,849 Other Deposits and Liabilities 8,262 — — — 8,262 Future Abandonment Cost 9,465 — — — 9,465 Intercompany Payables 1,023,697 3,663 — (1,027,360 ) — Total Liabilities 1,131,289 4,084 756,132 (1,027,360 ) 864,145 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 96 — 96 Additional Paid-In Capital 177,144 — 650,924 (177,144 ) 650,924 Accumulated Deficit (435,103 ) (4,084 ) (650,473 ) 451,889 (637,771 ) Total Stockholders’ Equity (257,959 ) (4,084 ) 548 274,745 13,250 Total Liabilities and Stockholders’ Equity $ 873,330 $ — $ 756,680 $ (752,615 ) $ 877,395 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 52,065 $ — $ — $ — $ 52,065 Other Operating Revenue 6 — — — 6 TOTAL OPERATING REVENUE 52,071 — — — 52,071 OPERATING EXPENSES Production and Lease Operating Expense 28,934 — — — 28,934 General and Administrative Expense 4,461 — 73 — 4,534 Gain on Disposal of Assets (1,834 ) — — — (1,834 ) Impairment Expense 1,546 — — — 1,546 Exploration Expense 220 — — — 220 Depreciation, Depletion, Amortization and Accretion 15,468 — — — 15,468 Other Operating Expense (21 ) — — — (21 ) TOTAL OPERATING EXPENSES 48,774 — 73 — 48,847 INCOME (LOSS) FROM OPERATIONS 3,297 — (73 ) — 3,224 OTHER INCOME (EXPENSE) Interest Expense (365 ) — (8,778 ) — (9,143 ) Gain (Loss) on Derivatives, Net 9,798 — (1,417 ) — 8,381 Other Expense (28 ) — — — (28 ) Gain on Extinguishment of Debt — — 249 — 249 Income From Equity in Consolidated Subsidiaries — — 12,702 (12,702 ) — TOTAL OTHER INCOME (EXPENSE) 9,405 — 2,756 (12,702 ) (541 ) INCOME BEFORE INCOME TAX 12,702 — 2,683 (12,702 ) 2,683 Income Tax Expense — — — — — NET INCOME ATTRIBUTABLE TO REX ENERGY $ 12,702 $ — $ 2,683 $ (12,702 ) $ 2,683 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 12,702 $ — $ 2,683 $ (12,702 ) $ 2,683 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 15,468 — — — 15,468 (Gain) Loss on Derivatives (9,798 ) — 1,417 — (8,381 ) Cash Settlements of Derivatives (3,443 ) — — — (3,443 ) Equity-based Compensation Expense 11 — 60 — 71 Non-cash Exploration Expense 11 — — — 11 Gain on Disposal of Assets (1,834 ) — — — (1,834 ) Gain on Extinguishment Debt — — (249 ) — (249 ) Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 6,081 — 6,081 Impairment Expense 1,546 — — — 1,546 Other Non-cash Income (66 ) — — — (66 ) Changes in operating assets and liabilities Accounts Receivable 5,174 — 167 — 5,341 Inventory, Prepaid Expenses and Other Assets 410 — 12 — 422 Accounts Payable and Accrued Liabilities (8,298 ) — 1,309 — (6,989 ) Other Assets and Liabilities (139 ) — — — (139 ) NET CASH PROVIDED BY OPERATING ACTIVITIES 11,744 — 11,480 (12,702 ) 10,522 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries (8,789 ) — (3,913 ) 12,702 — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 24,329 — — — 24,329 Acquisitions of Undeveloped Acreage (299 ) — — — (299 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (25,476 ) — — — (25,476 ) NET CASH USED IN INVESTING ACTIVITIES (10,235 ) — (3,913 ) 12,702 (1,446 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 21,500 — 21,500 Repayments of Long-Term Debt and Lines of Credit — — (28,500 ) — (28,500 ) Repayments of Loans and Other Long-Term Debt (131 ) — — — (131 ) Debt Issuance Costs — — (567 ) — (567 ) NET CASH USED IN FINANCING ACTIVITIES (131 ) — (7,567 ) — (7,698 ) NET INCREASE IN CASH 1,378 — — — 1,378 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 5,072 $ — $ 3 $ — $ 5,075 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 and Long-Term Debt, Net of Issuance Costs — — 113,785 — 113,785 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges — — 641,762 — 641,762 Discount on Senior Notes – Net — — (3,601 ) — (3,601 ) Other Long-Term Debt 3,409 — — — 3,409 Other Deposits and Liabilities 8,671 — — — 8,671 Future Abandonment Cost 8,736 — — — 8,736 Intercompany Payables 1,032,050 3,663 — (1,035,713 ) — Total Liabilities 1,158,922 4,084 756,404 (1,035,713 ) 883,697 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 95 — 95 Additional Paid-In Capital 177,144 — 650,584 (177,144 ) 650,584 Accumulated 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 March 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 25,673 $ — $ — $ — $ 25,673 Other Operating Revenue 13 — — — 13 TOTAL OPERATING REVENUE 25,686 — — — 25,686 OPERATING EXPENSES Production and Lease Operating Expense 24,451 — — — 24,451 General and Administrative Expense 5,299 — (15 ) — 5,284 Loss on Disposal of Assets 11 — — — 11 Impairment Expense 10,641 — — — 10,641 Exploration Expense 936 — — — 936 Depreciation, Depletion, Amortization and Accretion 16,501 10 — — 16,511 Other Operating Expense 327 — — — 327 TOTAL OPERATING EXPENSES 58,166 10 (15 ) — 58,161 INCOME (LOSS) FROM OPERATIONS (32,480 ) (10 ) 15 — (32,475 ) OTHER INCOME (EXPENSE) Interest Expense (270 ) — (12,760 ) — (13,030 ) Gain on Derivatives, Net 4,049 — — — 4,049 Debt Exchange Expense — — (8,480 ) — (8,480 ) Loss From Equity in Consolidated Subsidiaries (8 ) — (38,151 ) 38,159 — TOTAL OTHER INCOME (EXPENSE) 3,771 — (59,391 ) 38,159 (17,461 ) LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX (28,709 ) (10 ) (59,376 ) 38,159 (49,936 ) Income Tax Expense (1,950 ) — (765 ) — (2,715 ) LOSS FROM CONTINUING OPERATIONS (30,659 ) (10 ) (60,141 ) 38,159 (52,651 ) Income (Loss) From Discontinued Operations, Net of Income Tax (7,492 ) 2 — — (7,490 ) NET LOSS (38,151 ) (8 ) (60,141 ) 38,159 (60,141 ) Preferred Stock Dividends — — (2,105 ) — (2,105 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (38,151 ) $ (8 ) $ (62,246 ) $ 38,159 $ (62,246 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Loss $ (38,151 ) $ (8 ) $ (60,141 ) $ 38,159 $ (60,141 ) Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Gain on Derivatives, Net (4,049 ) — — — (4,049 ) Cash Settlements of Derivatives 12,994 — — — 12,994 Equity-based Compensation Expense 6 — (27 ) — (21 ) Non-cash Exploration Expense 843 — — — 843 Gain on Disposal of Assets (30 ) — — — (30 ) Amortization of net Bond Discount and Deferred Financing Costs — — 547 — 547 Deferred Income Tax Expense 1,326 1 765 — 2,092 Impairment Expense 14,184 — 14,184 (14,184 ) 14,184 Other Non-cash Income (29 ) — — — (29 ) Changes in operating assets and liabilities Accounts Receivable 15,852 10 (20,735 ) — (4,873 ) Inventory, Prepaid Expenses and Other Assets 648 — 12 — 660 Accounts Payable and Accrued Liabilities 1,921 21 (2,250 ) — (308 ) Other Assets and Liabilities (170 ) — — — (170 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,724 53 (67,645 ) 23,975 (18,893 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 29 (21 ) 23,967 (23,975 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 71 — — — 71 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,266 ) — — — (5,266 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (15,036 ) (32 ) — — (15,068 ) NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES (741 ) (53 ) 23,967 (23,975 ) (802 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 46,500 — 46,500 Repayments of Loans and Other Long-Term Debt (184 ) — — — (184 ) Debt Issuance Costs — — (2,821 ) — (2,821 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (184 ) — 43,679 — 43,495 NET INCREASE IN CASH 23,799 — 1 — 23,800 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 24,888 $ — $ 3 $ — $ 24,891

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	18. SUBSEQUENT EVENTS Term Loan and Retirement of Revolving Line of Credit On April 28, 2017 (the “Effective Date”), we entered into the 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 amended and restated our existing amended and restated senior secured revolving credit agreement (the “Existing Credit Agreement”). The Term Loan provides for (x) a $143,500,000 secured term loan facility (the “Term Facility”) secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit subfacility (the “Letter of Credit Subfacility”). 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: (i) three month LIBOR multiplied by (ii) 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. 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 (x) 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 (y) 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 dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions. The Term Loan also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after December 31, 2017, the PDP Coverage Ratio (as defined in the Term Loan) will not be less than 1.65 to 1.00; (2) as of the last day of any fiscal quarter ending on or after March 31, 2017, the ratio of Net Senior Secured Debt (as defined in the Term Loan) as of such date to EBITDAX (as defined in the Term Loan) for the period of four fiscal quarters then ending on such day will not be greater than 3.25 to 1.00 (provided that EBITDAX for the four fiscal quarters ending on (i) March 31, 2017 shall be EBITDAX for the fiscal quarter then ending multiplied by four and (ii) June 30, 2017 shall be EBITDAX for the two fiscal quarters then ending multiplied by two); and (3) as of the last day of any fiscal quarter ending on or after September 30, 2017, the ratio EBITDAX for the four fiscal quarters then ending to cash interest expense will not be less than (i) 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2017 and (ii) 1.30 to 1.00 for each fiscal quarter thereafter. 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. The foregoing descriptions of the Term Loan and the Guaranty and Collateral Agreement do not purport to be complete and are qualified in their entirety by reference to the complete text of these agreements. A copy of the Term Loan Credit Agreement and the Amended and Restated Guaranty and Collateral Agreement will be filed with the our Periodic Report on Form 10-Q for the quarter ending June 30, 2017.

Recently Issued Accounting Pr25

Recently Issued Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 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)	3 Months Ended
	Mar. 31, 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) March 31, 2017 Beginning Balance at January 1, 2017 $ 9,865 Future Abandonment Obligation Incurred $ 1,034 Future Abandonment Obligation Settled $ (112 ) Future Abandonment Obligation Cancelled or Sold $ (262 ) Future Abandonment Obligation Revision of Estimated Obligation $ 57 Future Abandonment Obligation Accretion Expense $ 570 Total Future Abandonment Cost 1 $ 11,152 1

Discontinued Operations_Asset27

Discontinued Operations/Assets Held For Sale (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2017, the first two 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 March 31, 2017, we have the potential to receive up to $8.1 million of additional proceeds, during the nine 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) 3/31/2017 $ 56.25 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).
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 month periods ended March 31, 2017 and 2016. For the Three Months Ended March 31, ($ in Thousands) 2017 2016 Revenues: Oil Sales $ — $ 4,821 Total Operating Revenue — 4,821 Costs and Expenses: Production and Lease Operating Expense — 5,698 General and Administrative Expense — 778 Gain on Disposal of Assets — (42 ) Impairment Expense — 3,543 Exploration Expense — 58 Depreciation, Depletion, Amortization and Accretion — 2,897 Interest Expense — 2 Other Income — (1 ) Total Costs and Expenses — 12,933 Loss From Discontinued Operations, Before Income Taxes — (8,112 ) Income Tax Benefit — 622 Loss From Discontinued Operations, Net of Taxes $ — $ (7,490 ) Production: Crude Oil (Bbls) — 158,304

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Components of Long-Term Debt and Lines of Credit	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at March 31, 2017 and December 31, 2016: ($ in Thousands) March 31, 2017 (unaudited) December 31, 2016 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges (a)(c) $ 650,758 $ 641,762 Discount on Senior Notes, Net (7,389 ) (3,601 ) Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs (b)(d) 106,573 113,785 Capital Leases and Other Obligations (d) 4,650 4,173 Total Debt 754,592 756,119 Less Current Portion of Long-Term Debt (801 ) (764 ) Total Long-Term Debt $ 753,791 $ 755,355 (a) Includes unamortized debt issuance costs of approximately ($17.3) million and ($7.9) million as of March 31, 2017 and December 31, 2016, respectively. ( b ) Includes unamortized debt issuance costs of approximately $4.1 million and $3.9 million as of March 31, 2017 and December 31, 2016, respectively. (c) Includes unamortized deferred gain on debt exchange of approximately $32.8 million and $32.7 million as of March 31, 2017 and December 31, 2016, respectively, as a result of debt exchange transactions completed subsequent to the March 31, 2016 Exchange. (d) The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three months ended March 31, 2017 was approximately 3.7 %. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2017 was approximately 10.0%.
Principal Maturity Schedule for Total Debt Outstanding	The following is the principal maturity schedule for debt outstanding as of March 31, 2017: 2017 $ 587 2018 908 2019 111,746 2020 596,565 2021 802 Thereafter 5,364 Total (a) $ 715,972 (a) Excludes $7.4 million net discount on Senior Notes, $32.8 million of deferred gain on Senior Notes, and ($13.2) million of debt issuance costs

Derivative Instruments And Fa29

Derivative Instruments And Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016: For the Three Months Ended March 31, ($ in Thousands) 2017 2016 Oil $ 1,137 $ 325 Natural Gas (59 ) 5,363 NGLs 8,720 (1,621 ) Refined Products — (18 ) Contingent Consideration (1,417 ) — Gain on Derivatives, Net $ 8,381 $ 4,049
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2017 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2017 - Swaps 81,000 Bbls $ — $ — $ — $ 53.00 $ 94 2017 - Deferred Put Spreads 15,000 Bbls 51.00 51.00 — — — 2017 - Collars 48,000 Bbls — 45.00 57.20 — — 2017 - Three-Way Collars 93,000 Bbls 40.16 49.68 61.50 — 108 2018 - Swaps 60,000 Bbls — — — 54.00 186 2018 - Collars 18,000 Bbls — 53.00 60.00 — — 2018 - Three-Way Collars 60,000 Bbls 43.00 52.00 62.30 — 92 375,000 Bbls $ 480 Natural Gas 2017 - Swaps 11,000,000 Mcf — — — 3.11 $ (1,332 ) 2017 - Swaptions 2,400,000 Mcf — — — 3.33 36 2017 - Cap Swaps 3,900,000 Mcf 2.35 — — 2.81 (1,591 ) 2017 - Collars 1,700,000 Mcf — 2.54 3.20 — (382 ) 2017 - Three-Way Collars 17,510,000 Mcf 2.33 3.01 3.87 — (133 ) 2017 - Calls 8,380,100 Mcf — — 4.51 — (338 ) 2017 - Basis Swaps - Dominion South 16,405,000 Mcf — — — (0.80 ) (2,467 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) 46 2018 - Swaps 12,585,000 Mcf — — — 3.14 289 2018 - Swaptions — Mcf — — — (200 ) 2018 - Three-Way Collars 8,775,000 Mcf 2.30 2.89 3.58 — (509 ) 2018 - Calls 16,489,900 Mcf — — 4.64 — (753 ) 2018 - Collars 450,000 Mcf — 3.20 3.65 — (33 ) 2018 - Basis Swaps - Dominion South 18,980,000 Mcf — — — (0.80 ) (3,417 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf (0.13 ) 62 2019 - Swaps 900,000 Mcf — — — 3.00 60 2019 - Basis Swaps - Dominion South 18,980,000 Mcf — — — (0.81 ) (3,190 ) 2020 - Basis Swaps - Dominion South 13,542,000 Mcf — — — (0.80 ) (1,551 ) 2021 - Basis Swaps - Dominion South 6,234,000 Mcf — — — (0.73 ) (461 ) 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (460 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (461 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (460 ) 198,381,000 Mcf $ (17,245 ) NGLs 2017 - C3+ NGL Swaps 1,689,000 Bbls — — — 0.71 $ (2,455 ) 2017 - Ethane Swaps 840,000 Bbls — — — 0.25 (237 ) 2018 - C3+ NGL Swaps 1,068,000 Bbls — — — 0.76 1,684 2018 - Ethane Swaps 660,000 Bbls — — — 0.31 (15 ) 2019 - Ethane Swaps 240,000 Bbls — — — 0.31 (75 ) 4,497,000 Bbls $ (1,098 )
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 March 31, 2017 and December 31, 2016 is summarized below: March 31, December 31, ($ in Thousands) 2017 2016 Short-Term Derivative Assets: Crude Oil—Three-Way Collars 131 — Crude Oil—Swaps 175 — NGL—Swaps 1,291 — Natural Gas—Swaps 453 206 Natural Gas—Cap Swaps — 61 Natural Gas—Basis Swaps 132 232 Natural Gas—Three-Way Collars 523 151 Natural Gas—Swaption 170 — Contingent Consideration - Sale of Illinois Basin 555 1,223 Total Short-Term Derivative Assets $ 3,430 $ 1,873 Long-Term Derivative Assets: Crude Oil—Three-Way Collars $ 69 $ — Crude Oil—Swaps $ 143 NGL—Swaps 1,177 — Natural Gas—Swaps 707 206 Natural Gas—Basis Swaps 99 293 Natural Gas—Three-Way Collars 133 — Contingent Consideration - Sale of Illinois Basin 964 1,713 Total Long-Term Derivative Assets $ 3,292 $ 2,212 Total Derivative Assets $ 6,722 $ 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 (19 ) (220 ) NGL—Swaps (3,566 ) (9,895 ) Natural Gas—Three-Way Collars (889 ) (2,397 ) Natural Gas—Cap Swaps (1,591 ) (3,364 ) Natural Gas—Collars (415 ) (873 ) Natural Gas—Basis Swaps (3,561 ) (640 ) Natural Gas—Call (527 ) (1,478 ) Natural Gas—Swaption (184 ) (1,258 ) Natural Gas—Swaps (2,049 ) (4,673 ) Total Short - Term Derivative Liabilities $ (12,801 ) $ (25,025 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars (58 ) Crude Oil—Swaps (19 ) (146 ) NGL—Swaps — (2,200 ) Natural Gas—Swaps (94 ) (1,004 ) Natural Gas—Swaption (150 ) (167 ) Natural Gas—Basis Swaps (9,028 ) (1,260 ) Natural Gas—Collars — (115 ) Natural Gas—Call (565 ) (491 ) Natural Gas—Three-Way Collars (409 ) (1,786 ) Total Long-Term Derivative Liabilities $ (10,265 ) $ (7,227 ) Total Derivative Liabilities $ (23,066 ) $ (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 March 31, 2017 ($ in Thousands) Total Carrying Value as of March 31, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (16,344 ) $ — $ (16,344 ) $ — 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: March 31, 2017 December 31, 2016 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 650,758 $ 253,796 $ 641,762 $ 147,605 Secured Line of Credit, Net of Issuance Costs 106,573 106,573 113,785 113,785 Capital Leases and Other Obligations 4,650 3,129 4,173 3,234 Total $ 761,981 $ 363,498 $ 759,720 $ 264,624

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2017 ($ in Thousands) 2017 2016 Income Tax Benefit $ — $ (2,715 ) Effective Tax Rate 0.0 % -5.4 %

Employee Benefit And Equity P31

Employee Benefit And Equity Plans (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2017 is as follows: Outstanding Exercisable Exercise Price Number Outstanding at March 31, 2017 Weighted-Average Exercise Price Number Exercisable at March 31, 2017 Weighted-Average Exercise Price $ 0.97 27,500 $ 0.97 — $ 0.97 $ 1.69 753,428 $ 1.69 251,135 $ 1.69 $ 4.05 40,000 $ 4.05 — $ 4.05 $ 4.90 40,000 $ 4.90 6,666 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,171,100 $ 4.16 567,973 $ 6.47
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 three months ended March 31, 2017 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2016 2,427,494 $ 2.63 Awards 1,012,242 0.52 Forfeitures (191,353 ) 8.69 Vested (384,236 ) 2.13 Restricted stock awards, as of March 31, 2017 2,864,147 $ 1.55

Commitments and Contingencies (

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	As of March 31, 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 months ended March 31, 2017 and 2016, was approximately $0.2 million and $0.3 million, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2017 $ 749 2018 565 2019 563 2020 422 2021 — Thereafter — Total $ 2,299
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 $ 32,822 2018 47,350 2019 47,522 2020 46,226 2021 43,285 Thereafter 479,768 Total $ 696,973
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)	3 Months Ended
	Mar. 31, 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 March 31, Numerator: 2017 2016 Net Income (Loss) From Continuing Operations $ 2,683 $ (52,651 ) Net Loss From Discontinued Operations — (7,490 ) Less: Preferred Stock Dividends (598 ) (2,105 ) Net Income (Loss) Attributable to Common Shareholders $ 2,085 $ (62,246 ) Denominator: Weighted Average Common Shares Outstanding - Basic 97,687 56,003 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 97,687 56,003 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Income (Loss) From Continuing Operations $ 0.02 $ (0.98 ) — Net Loss From Discontinued Operations — (0.13 ) — Net Income (Loss) Attributable to Common Shareholders $ 0.02 $ (1.11 ) Diluted — Net Income (Loss) From Discontinued Operations $ 0.02 $ (0.98 ) — Net Loss From Discontinued Operations — (0.13 ) — Net Income (Loss) Attributable to Common Shareholders $ 0.02 $ (1.11 )

Condensed Consolidating Finan34

Condensed Consolidating Financial Information (Tables)	3 Months Ended
	Mar. 31, 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 MARCH 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non- Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 5,072 $ — $ 3 $ — $ 5,075 Accounts Receivable 25,264 — — — 25,264 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 2,875 — 555 — 3,430 Inventory, Prepaid Expenses and Other 2,112 — 12 — 2,124 Total Current Assets 35,323 — 618 — 35,941 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 963,481 — — — 963,481 Unevaluated Oil and Gas Properties 207,821 — — — 207,821 Other Property and Equipment 21,863 — — — 21,863 Wells and Facilities in Progress 40,740 — — — 40,740 Pipelines 21,262 — — — 21,262 Total Property and Equipment 1,255,167 — — — 1,255,167 Less: Accumulated Depreciation, Depletion and Amortization (419,500 ) — — — (419,500 ) Net Property and Equipment 835,667 — — — 835,667 Other Assets 2,495 — — — 2,495 Intercompany Receivables — — 1,027,360 (1,027,360 ) — Investment in Subsidiaries – Net (2,484 ) — (272,261 ) 274,745 — Long-Term Derivative Instruments 2,329 — 963 — 3,292 Total Assets $ 873,330 $ — $ 756,680 $ (752,615 ) $ 877,395 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 36,838 $ — $ — $ — $ 36,838 Current Maturities of Long-Term Debt 801 — — — 801 Accrued Liabilities 25,311 421 6,190 — 31,922 Short-Term Derivative Instruments 12,801 — — — 12,801 Total Current Liabilities 75,751 421 6,190 — 82,362 Long-Term Derivative Instruments 10,265 — — — 10,265 Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs — — 106,573 — 106,573 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges — — 650,758 — 650,758 Discount on Senior Notes, Net — — (7,389 ) — (7,389 ) Other Long-Term Debt 3,849 — — — 3,849 Other Deposits and Liabilities 8,262 — — — 8,262 Future Abandonment Cost 9,465 — — — 9,465 Intercompany Payables 1,023,697 3,663 — (1,027,360 ) — Total Liabilities 1,131,289 4,084 756,132 (1,027,360 ) 864,145 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 96 — 96 Additional Paid-In Capital 177,144 — 650,924 (177,144 ) 650,924 Accumulated Deficit (435,103 ) (4,084 ) (650,473 ) 451,889 (637,771 ) Total Stockholders’ Equity (257,959 ) (4,084 ) 548 274,745 13,250 Total Liabilities and Stockholders’ Equity $ 873,330 $ — $ 756,680 $ (752,615 ) $ 877,395 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 and Long-Term Debt, Net of Issuance Costs — — 113,785 — 113,785 Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges — — 641,762 — 641,762 Discount on Senior Notes – Net — — (3,601 ) — (3,601 ) Other Long-Term Debt 3,409 — — — 3,409 Other Deposits and Liabilities 8,671 — — — 8,671 Future Abandonment Cost 8,736 — — — 8,736 Intercompany Payables 1,032,050 3,663 — (1,035,713 ) — Total Liabilities 1,158,922 4,084 756,404 (1,035,713 ) 883,697 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 95 — 95 Additional Paid-In Capital 177,144 — 650,584 (177,144 ) 650,584 Accumulated 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 MARCH 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 52,065 $ — $ — $ — $ 52,065 Other Operating Revenue 6 — — — 6 TOTAL OPERATING REVENUE 52,071 — — — 52,071 OPERATING EXPENSES Production and Lease Operating Expense 28,934 — — — 28,934 General and Administrative Expense 4,461 — 73 — 4,534 Gain on Disposal of Assets (1,834 ) — — — (1,834 ) Impairment Expense 1,546 — — — 1,546 Exploration Expense 220 — — — 220 Depreciation, Depletion, Amortization and Accretion 15,468 — — — 15,468 Other Operating Expense (21 ) — — — (21 ) TOTAL OPERATING EXPENSES 48,774 — 73 — 48,847 INCOME (LOSS) FROM OPERATIONS 3,297 — (73 ) — 3,224 OTHER INCOME (EXPENSE) Interest Expense (365 ) — (8,778 ) — (9,143 ) Gain (Loss) on Derivatives, Net 9,798 — (1,417 ) — 8,381 Other Expense (28 ) — — — (28 ) Gain on Extinguishment of Debt — — 249 — 249 Income From Equity in Consolidated Subsidiaries — — 12,702 (12,702 ) — TOTAL OTHER INCOME (EXPENSE) 9,405 — 2,756 (12,702 ) (541 ) INCOME BEFORE INCOME TAX 12,702 — 2,683 (12,702 ) 2,683 Income Tax Expense — — — — — NET INCOME ATTRIBUTABLE TO REX ENERGY $ 12,702 $ — $ 2,683 $ (12,702 ) $ 2,683 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED March 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 25,673 $ — $ — $ — $ 25,673 Other Operating Revenue 13 — — — 13 TOTAL OPERATING REVENUE 25,686 — — — 25,686 OPERATING EXPENSES Production and Lease Operating Expense 24,451 — — — 24,451 General and Administrative Expense 5,299 — (15 ) — 5,284 Loss on Disposal of Assets 11 — — — 11 Impairment Expense 10,641 — — — 10,641 Exploration Expense 936 — — — 936 Depreciation, Depletion, Amortization and Accretion 16,501 10 — — 16,511 Other Operating Expense 327 — — — 327 TOTAL OPERATING EXPENSES 58,166 10 (15 ) — 58,161 INCOME (LOSS) FROM OPERATIONS (32,480 ) (10 ) 15 — (32,475 ) OTHER INCOME (EXPENSE) Interest Expense (270 ) — (12,760 ) — (13,030 ) Gain on Derivatives, Net 4,049 — — — 4,049 Debt Exchange Expense — — (8,480 ) — (8,480 ) Loss From Equity in Consolidated Subsidiaries (8 ) — (38,151 ) 38,159 — TOTAL OTHER INCOME (EXPENSE) 3,771 — (59,391 ) 38,159 (17,461 ) LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX (28,709 ) (10 ) (59,376 ) 38,159 (49,936 ) Income Tax Expense (1,950 ) — (765 ) — (2,715 ) LOSS FROM CONTINUING OPERATIONS (30,659 ) (10 ) (60,141 ) 38,159 (52,651 ) Income (Loss) From Discontinued Operations, Net of Income Tax (7,492 ) 2 — — (7,490 ) NET LOSS (38,151 ) (8 ) (60,141 ) 38,159 (60,141 ) Preferred Stock Dividends — — (2,105 ) — (2,105 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (38,151 ) $ (8 ) $ (62,246 ) $ 38,159 $ (62,246 )
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 12,702 $ — $ 2,683 $ (12,702 ) $ 2,683 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 15,468 — — — 15,468 (Gain) Loss on Derivatives (9,798 ) — 1,417 — (8,381 ) Cash Settlements of Derivatives (3,443 ) — — — (3,443 ) Equity-based Compensation Expense 11 — 60 — 71 Non-cash Exploration Expense 11 — — — 11 Gain on Disposal of Assets (1,834 ) — — — (1,834 ) Gain on Extinguishment Debt — — (249 ) — (249 ) Non-cash Interest Expense related to Debt Restructurings and Exchanges — — 6,081 — 6,081 Impairment Expense 1,546 — — — 1,546 Other Non-cash Income (66 ) — — — (66 ) Changes in operating assets and liabilities Accounts Receivable 5,174 — 167 — 5,341 Inventory, Prepaid Expenses and Other Assets 410 — 12 — 422 Accounts Payable and Accrued Liabilities (8,298 ) — 1,309 — (6,989 ) Other Assets and Liabilities (139 ) — — — (139 ) NET CASH PROVIDED BY OPERATING ACTIVITIES 11,744 — 11,480 (12,702 ) 10,522 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries (8,789 ) — (3,913 ) 12,702 — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 24,329 — — — 24,329 Acquisitions of Undeveloped Acreage (299 ) — — — (299 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (25,476 ) — — — (25,476 ) NET CASH USED IN INVESTING ACTIVITIES (10,235 ) — (3,913 ) 12,702 (1,446 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 21,500 — 21,500 Repayments of Long-Term Debt and Lines of Credit — — (28,500 ) — (28,500 ) Repayments of Loans and Other Long-Term Debt (131 ) — — — (131 ) Debt Issuance Costs — — (567 ) — (567 ) NET CASH USED IN FINANCING ACTIVITIES (131 ) — (7,567 ) — (7,698 ) NET INCREASE IN CASH 1,378 — — — 1,378 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 5,072 $ — $ 3 $ — $ 5,075 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Loss $ (38,151 ) $ (8 ) $ (60,141 ) $ 38,159 $ (60,141 ) Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Gain on Derivatives, Net (4,049 ) — — — (4,049 ) Cash Settlements of Derivatives 12,994 — — — 12,994 Equity-based Compensation Expense 6 — (27 ) — (21 ) Non-cash Exploration Expense 843 — — — 843 Gain on Disposal of Assets (30 ) — — — (30 ) Amortization of net Bond Discount and Deferred Financing Costs — — 547 — 547 Deferred Income Tax Expense 1,326 1 765 — 2,092 Impairment Expense 14,184 — 14,184 (14,184 ) 14,184 Other Non-cash Income (29 ) — — — (29 ) Changes in operating assets and liabilities Accounts Receivable 15,852 10 (20,735 ) — (4,873 ) Inventory, Prepaid Expenses and Other Assets 648 — 12 — 660 Accounts Payable and Accrued Liabilities 1,921 21 (2,250 ) — (308 ) Other Assets and Liabilities (170 ) — — — (170 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,724 53 (67,645 ) 23,975 (18,893 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 29 (21 ) 23,967 (23,975 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 71 — — — 71 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,266 ) — — — (5,266 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (15,036 ) (32 ) — — (15,068 ) NET CASH PROVIDED BY (USED) IN INVESTING ACTIVITIES (741 ) (53 ) 23,967 (23,975 ) (802 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 46,500 — 46,500 Repayments of Loans and Other Long-Term Debt (184 ) — — — (184 ) Debt Issuance Costs — — (2,821 ) — (2,821 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (184 ) — 43,679 — 43,495 NET INCREASE IN CASH 23,799 — 1 — 23,800 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 24,888 $ — $ 3 $ — $ 24,891

Future Abandonment Cost - Addit

Future Abandonment Cost - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 570	$ 200

Future Abandonment Cost (Detail

Future Abandonment Cost (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance at January 1, 2017		$ 9,865
Future Abandonment Obligation Incurred		1,034
Future Abandonment Obligation Settled		(112)
Future Abandonment Obligation Cancelled or Sold		(262)
Future Abandonment Obligation Revision of Estimated Obligation		57
Future Abandonment Obligation Accretion Expense		570	$ 200
Total Future Abandonment Cost	[1]	$ 11,152
[1]	Includes approximately $1.7 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) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 31,922	$ 37,207
Remediation Property for Sale, Abandonment or Disposal
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 1,700

Discontinued Operations_ Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details) - Illinois Basin Operations - Discontinued Operations Assets Held For Sale	Jun. 14, 2016USD ($)	Mar. 31, 2017USD ($)aQuarterlyInstallmentbbl	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)
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	$ 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		2
Expiration of quarterly measurement period remaining number | QuarterlyInstallment		9
Additional proceeds receivable for first two 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 nine quarterly installments		$ 8,100,000

Average Spot Price (Details)

Average Spot Price (Details) - Illinois Basin Operations - Discontinued Operations Assets Held For Sale	3 Months Ended
	Mar. 31, 2017$ / bbl	[1]
3/31/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	56.25
6/30/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	58.25
9/30/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	60.25
12/31/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	60.75
3/31/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	61.25
6/30/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	61.75
9/30/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	62.25
12/31/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	62.75
3/31/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	63.25
6/30/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	63.75
[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
	Mar. 31, 2017USD ($)	Mar. 31, 2016USD ($)bbl
Revenues:
TOTAL OPERATING REVENUE	$ 52,071	$ 25,686
Costs and Expenses:
Production and Lease Operating Expense	28,934	24,451
General and Administrative Expense	4,534	5,284
Gain on Disposal of Assets	(1,834)	11
Impairment Expense	1,546	10,641
Exploration Expense	220	936
Depreciation, Depletion, Amortization and Accretion	15,468	16,511
Interest Expense	9,143	13,030
Other Income	$ 28
Loss From Discontinued Operations, Net of Taxes		(7,490)
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Revenues:
Oil Sales		4,821
TOTAL OPERATING REVENUE		4,821
Costs and Expenses:
Production and Lease Operating Expense		5,698
General and Administrative Expense		778
Gain on Disposal of Assets		(42)
Impairment Expense		3,543
Exploration Expense		58
Depreciation, Depletion, Amortization and Accretion		2,897
Interest Expense		2
Other Income		(1)
Total Costs and Expenses		12,933
Loss From Discontinued Operations, Before Income Taxes		(8,112)
Income Tax Benefit		622
Loss From Discontinued Operations, Net of Taxes		$ (7,490)
Production:
Crude Oil (Bbls) | bbl		158,304

Business and Oil and Gas Prop41

Business and Oil and Gas Property Dispositions - Additional Information (Details)	Jan. 11, 2017USD ($)aMMcfeWell	May 20, 2016USD ($)Well	Mar. 01, 2016Well	Jan. 31, 2017USD ($)	Mar. 31, 2017USD ($)Well	Jun. 30, 2016USD ($)
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 | $					$ 86,700,000
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					30
Number of wells committed for line and producing					45
Number of drilled well that is awaiting completion					15
Benefit Street Partners Limited Liability Corporation | Maximum
Business Acquisition And Dispositions [Line Items]
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	3 Months Ended
	Mar. 31, 2017Customer
Purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	95.80%
Number of major customers	5
Largest single purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	51.00%

Long-Term Debt - Senior Credit

Long-Term Debt - Senior Credit Facility and Term Loan - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Line of credit facility, amount outstanding					$ 110.7	$ 117.7
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity					46.3
Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity					$ 190
Term Loan | Minimum | Scenario, Forecast
Debt Instrument [Line Items]
Criteria of net senior secured debt to EBITDAX				325.00%
EBITDAX to interest expense ratio	130.00%	100.00%
Criteria PDP coverage ratio		165.00%
Term Loan | Maximum | Scenario, Forecast
Debt Instrument [Line Items]
Trailing twelve months criteria EBITDAX to interest expense ratio			100.00%

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Details) - USD ($) shares in Millions	Mar. 31, 2016	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Debt Instrument [Line Items]
Share of common stock			10.1
Gain recognized due to troubled debt exchanges			$ (8,480,000)
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		$ 567,000	2,821,000
Issuance of unrestricted common stock shares		0.3		22.7
Gain on Extinguishments of Debt		$ 249,000
Trailing quarters fixed charge coverage ratio		225.00%
Fixed charge coverage ratio		126.00%
Senior Notes additional borrowings		$ 112,200,000
Discount on Senior Notes, Net		7,389,000		$ 3,601,000
Amortization of net premium		$ 3,800,000
Interest Payments One Through Three
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment		semi-annual
Maximum
Debt Instrument [Line Items]
Senior notes offered for exchange			675,000,000
New Notes
Debt Instrument [Line Items]
Gain recognized due to 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		$ 500,000		$ 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
Debt Instrument [Line Items]
Interest rate		8.875%		8.875%
6.25% Senior Notes
Debt Instrument [Line Items]
Interest rate		6.25%		6.25%

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Details) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges	[1],[2]	$ 650,758	$ 641,762
Discount on Senior Notes, Net		(7,389)	(3,601)
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs	[3],[4]	106,573	113,785
Capital Leases and Other Obligations	[4]	4,650	4,173
Total Debt		754,592	756,119
Less Current Portion of Long-Term Debt		(801)	(764)
Total Long-Term Debt		$ 753,791	$ 755,355
[1]	Includes unamortized debt issuance costs of approximately ($17.3) million and ($7.9) million as of March 31, 2017 and December 31, 2016, respectively.
[2]	Includes unamortized deferred gain on debt exchange of approximately $32.8 million and $32.7 million as of March 31, 2017 and December 31, 2016, respectively, as a result of debt exchange transactions completed subsequent to the March 31, 2016 Exchange.
[3]	Includes unamortized debt issuance costs of approximately $4.1 million and $3.9 million as of March 31, 2017 and December 31, 2016, respectively.
[4]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three months ended March 31, 2017 was approximately 3.7 %. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2017 was approximately 10.0%.

Components of Long-Term Debt 46

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Senior Secured Line of Credit and Long-Term Debt, Capital Leases and Other Obligations
Debt Instrument [Line Items]
Unamortized debt issuance expense	$ 17.3	$ 7.9
Senior Line of Credit
Debt Instrument [Line Items]
Unamortized debt issuance expense	4.1	3.9
Senior Secured Line of Credit and Long-Term Debt
Debt Instrument [Line Items]
Unamortized deferred gain on debt exchange	$ 32.8	$ 32.7
Senior Credit Facility
Debt Instrument [Line Items]
Average interest rate	3.70%
Capital Leases and Other Obligations
Debt Instrument [Line Items]
Average interest rate	10.00%

Principal Maturity Schedule for

Principal Maturity Schedule for Debt Outstanding (Details) $ in Thousands	Mar. 31, 2017USD ($)
Debt Disclosure [Abstract]
2,017	$ 587
2,018	908
2,019	111,746
2,020	596,565
2,021	802
Thereafter	5,364
Total	$ 715,972	[1]
[1]	Excludes $7.4 million net discount on Senior Notes, $32.8 million of deferred gain on Senior Notes, and ($13.2) million of debt issuance costs

Principal Maturity Schedule f48

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) $ in Millions	Mar. 31, 2017USD ($)
Debt Instrument [Line Items]
Senior notes, net discount	$ 7.4
Senior notes, deferred gain	32.8
New Notes
Debt Instrument [Line Items]
Debt issuance costs	$ (13.2)

Derivative Instruments and Fa49

Derivative Instruments and Fair Value Measurements - Additional Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives Received (Paid)	$ 3,443,000	$ (12,994,000)
Senior Line of Credit	110,700,000		$ 117,700,000
Senior Notes	600,700,000		601,200,000
Derivative interest rate outstanding	0	0
Derivatives asset (liability)	16,300,000		28,200,000
Impairment Expense	1,500,000	10,600,000
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	$ 1,500,000		$ 2,900,000
Crude Oil | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through remainder of 2017	100.00%
Natural Gas | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through remainder of 2017	100.00%
Natural Gas Liquids | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through remainder of 2017	100.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives Received (Paid)	$ (3,400,000)	$ 13,000,000

Schedule of Location and Amount

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ 8,381	$ 4,049
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	1,137	325
Refined Products
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net		(18)
Natural Gas
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(59)	5,363
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	8,720	$ (1,621)
Contingent Consideration
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (1,417)

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)$ / bbl$ / McfbblMcf
Crude Oil 2017 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	48,000
Floor | $ / bbl	45
Ceiling | $ / bbl	57.20
Crude Oil 2017 | Deferred Put Spreads
Derivatives Fair Value [Line Items]
Volume | bbl	15,000
Put Option | $ / bbl	51
Floor | $ / bbl	51
Crude Oil 2017 | Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	93,000
Put Option | $ / bbl	40.16
Floor | $ / bbl	49.68
Ceiling | $ / bbl	61.50
Derivatives asset (liability)	$ 108
Crude Oil 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	81,000
Swap | $ / bbl	53
Derivatives asset (liability)	$ 94
Crude Oil
Derivatives Fair Value [Line Items]
Volume | bbl	375,000
Derivatives asset (liability)	$ 480
Crude Oil Twenty Eighteen | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	18,000
Floor | $ / bbl	53
Ceiling | $ / bbl	60
Crude Oil Twenty Eighteen | 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)	$ 92
Crude Oil Twenty Eighteen | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	60,000
Swap | $ / bbl	54
Derivatives asset (liability)	$ 186
Natural Gas 2017 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	1,700,000
Floor | $ / Mcf	2.54
Ceiling | $ / Mcf	3.20
Derivatives asset (liability)	$ (382)
Natural Gas 2017 | Three-Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	17,510,000
Put Option | $ / Mcf	2.33
Floor | $ / Mcf	3.01
Ceiling | $ / Mcf	3.87
Derivatives asset (liability)	$ (133)
Natural Gas 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	11,000,000
Swap | $ / Mcf	3.11
Derivatives asset (liability)	$ (1,332)
Natural Gas 2017 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	2,400,000
Swap | $ / Mcf	3.33
Derivatives asset (liability)	$ 36
Natural Gas 2017 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	3,900,000
Put Option | $ / Mcf	2.35
Swap | $ / Mcf	2.81
Derivatives asset (liability)	$ (1,591)
Natural Gas 2017 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	16,405,000
Swap | $ / Mcf	(0.80)
Derivatives asset (liability)	$ (2,467)
Natural Gas 2017 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	8,380,100
Ceiling | $ / Mcf	4.51
Derivatives asset (liability)	$ (338)
Natural Gas 2017 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ 46
Natural Gas 2018 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	450,000
Floor | $ / Mcf	3.20
Ceiling | $ / Mcf	3.65
Derivatives asset (liability)	$ (33)
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)	$ (509)
Natural Gas 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	12,585,000
Swap | $ / Mcf	3.14
Derivatives asset (liability)	$ 289
Natural Gas 2018 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	0
Derivatives asset (liability)	$ (200)
Natural Gas 2018 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	18,980,000
Swap | $ / Mcf	(0.80)
Derivatives asset (liability)	$ (3,417)
Natural Gas 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	16,489,900
Ceiling | $ / Mcf	4.64
Derivatives asset (liability)	$ (753)
Natural Gas 2018 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ 62
Natural Gas 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	900,000
Swap | $ / Mcf	3
Derivatives asset (liability)	$ 60
Natural Gas 2019 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	18,980,000
Swap | $ / Mcf	(0.81)
Derivatives asset (liability)	$ (3,190)
Natural Gas 2020 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	13,542,000
Swap | $ / Mcf	(0.80)
Derivatives asset (liability)	$ (1,551)
Natural Gas 2021 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	6,234,000
Swap | $ / Mcf	(0.73)
Derivatives asset (liability)	$ (461)
Natural Gas 2022 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (460)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	198,381,000
Derivatives asset (liability)	$ (17,245)
Natural Gas 2023 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (461)
Natural Gas 2024 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (460)
Natural Gas Liquids Reserves 2017 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,689,000
Swap | $ / bbl	0.71
Derivatives asset (liability)	$ (2,455)
Natural Gas Liquids Reserves 2017 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	840,000
Swap | $ / bbl	0.25
Derivatives asset (liability)	$ (237)
Natural Gas Liquids Reserves 2018 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,068,000
Swap | $ / bbl	0.76
Derivatives asset (liability)	$ 1,684
Natural Gas Liquids Reserves 2018 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	660,000
Swap | $ / bbl	0.31
Derivatives asset (liability)	$ (15)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	4,497,000
Derivatives asset (liability)	$ (1,098)
Natural Gas Liquids Reserves 2019 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	240,000
Swap | $ / bbl	0.31
Derivatives asset (liability)	$ (75)

Combined Fair Value of Derivati

Combined Fair Value of Derivatives (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$ 3,430	$ 1,873
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	3,292	2,212
Total Derivative Assets	6,722	4,085
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(12,801)	(25,025)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(10,265)	(7,227)
Total Derivative Liabilities	(23,066)	(32,252)
Contingent Consideration | Sale of Illinois Basin
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	555	1,223
Contingent Consideration | Sale of Illinois Basin
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	964	1,713
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,291
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,177
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,566)	(9,895)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(2,200)
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	453	206
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	707	206
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(2,049)	(4,673)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(94)	(1,004)
Natural Gas | Three-Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	523	151
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	133
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(889)	(2,397)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(409)	(1,786)
Natural Gas | Cap Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		61
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(1,591)	(3,364)
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	132	232
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	99	293
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,561)	(640)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(9,028)	(1,260)
Natural Gas | Swaptions
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	170
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(184)	(1,258)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(150)	(167)
Natural Gas | Collars
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(415)	(873)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(115)
Natural Gas | Calls
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(527)	(1,478)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(565)	(491)
Crude Oil | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	175
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	143
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(19)	(220)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(19)	(146)
Crude Oil | Three-Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	131
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	$ 69
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 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	Mar. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (16,344)	$ (28,167)
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (16,344)	$ (28,167)

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Carrying Amount
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	$ 650,758	$ 641,762
Secured Line of Credit, Net of Issuance Costs	106,573	113,785
Capital Leases and Other Obligations	4,650	4,173
Total	761,981	759,720
Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	253,796	147,605
Secured Line of Credit, Net of Issuance Costs	106,573	113,785
Capital Leases and Other Obligations	3,129	3,234
Total	$ 363,498	$ 264,624

Schedule of Income Tax Included

Schedule of Income Tax Included in Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Tax Expense		$ (2,715)
Effective Tax Rate	(0.00%)	(5.40%)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Line Items]
Estimated annual effective tax rate from continue operations	0.00%	5.40%
Valuation allowance for deferred tax assets	$ 0
Statutory rate	35.00%
Estimated annual effective tax rate from continuing operations		(5.40%)
Income taxes benefit from continuing operations		$ 2,715,000
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	1 Months Ended	3 Months Ended
	Feb. 29, 2016	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	May 27, 2016
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized		200,000,000	100,000,000	200,000,000	200,000,000
Preferred Stock, shares authorized		100,000		100,000
Common Stock, shares issued		99,024,368		97,870,608
Common Stock, shares outstanding		99,024,368		97,870,608
Issuance of common stock		300,000
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]
Preferred stock convertible preferred stock		1,800,000
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		3,264
Dividend per share in amount		$ 600
Dividend per share percentage		6.00%
Quarterly cash dividend paid per share	$ 0
Accumulated dividends in arrears		$ 3
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Liquidation preference per share		$ 10,000

Employee Benefit and Equity P58

Employee Benefit and Equity Plans - Additional Information (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)Person$ / sharesshares	Mar. 31, 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	851,422
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
Aggregate intrinsic value of options exercisable	0
Unrecognized compensation expense	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		29
Stock-based compensation expense	100,000
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	900,000	$ 1,800,000
Unrecognized compensation expense	$ 1,400,000
Common stock issued by compensation committee | shares	1,012,242	420,901
Number of employees subjected to issuance of common stock | Person	28	22
Fair value of TSR awards of per share estimated on date of grant | $ / shares	$ 0.52
Unrecognized compensation expense weighted average period, in years	1 year 7 months 6 days
Vested stock | shares	384,236
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	179,519	235,573

Summary of Issued and Outstandi

Summary of Issued and Outstanding Stock Options (Details)	Mar. 31, 2017$ / sharesshares
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding | shares	1,171,100
Weighted-Average Exercise Price, Outstanding	$ 4.16
Number Exercisable | shares	567,973
Weighted-Average Exercise Price, Exercisable	$ 6.47
Exercise Price Range 0.97
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 0.97
Number Outstanding | shares	27,500
Weighted-Average Exercise Price, Outstanding	$ 0.97
Weighted-Average Exercise Price, Exercisable	0.97
Exercise Price Range 1.69
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 1.69
Number Outstanding | shares	753,428
Weighted-Average Exercise Price, Outstanding	$ 1.69
Number Exercisable | shares	251,135
Weighted-Average Exercise Price, Exercisable	$ 1.69
Exercise Price Range 4.05
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.05
Number Outstanding | shares	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.05
Weighted-Average Exercise Price, Exercisable	4.05
Exercise Price Range 4.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.90
Number Outstanding | shares	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.90
Number Exercisable | shares	6,666
Weighted-Average Exercise Price, Exercisable	$ 4.90
Exercise Price Range 5.04
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 5.04
Number Outstanding | shares	46,041
Weighted-Average Exercise Price, Outstanding	$ 5.04
Number Exercisable | shares	46,041
Weighted-Average Exercise Price, Exercisable	$ 5.04
Exercise Price Range 9.50
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.50
Number Outstanding | shares	75,000
Weighted-Average Exercise Price, Outstanding	$ 9.50
Number Exercisable | shares	75,000
Weighted-Average Exercise Price, Exercisable	$ 9.50
Exercise Price Range 9.99
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.99
Number Outstanding | shares	129,583
Weighted-Average Exercise Price, Outstanding	$ 9.99
Number Exercisable | shares	129,583
Weighted-Average Exercise Price, Exercisable	$ 9.99
Exercise Price Range 10.42
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 10.42
Number Outstanding | shares	29,548
Weighted-Average Exercise Price, Outstanding	$ 10.42
Number Exercisable | shares	29,548
Weighted-Average Exercise Price, Exercisable	$ 10.42
Exercise Price Range 22.34
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 22.34
Number Outstanding | shares	30,000
Weighted-Average Exercise Price, Outstanding	$ 22.34
Number Exercisable | shares	30,000
Weighted-Average Exercise Price, Exercisable	$ 22.34

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	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	2,427,494
Awards, Number of Shares	1,012,242	420,901
Forfeitures, Number of Shares	(191,353)
Vested, Number of Shares	(384,236)
Stock awards, ending balance, Number of Shares	2,864,147
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 2.63
Awards, Weighted Average Grant Date Fair Value	0.52
Forfeitures, Weighted Average Grant Date Fair Value	8.69
Vested, Weighted Average Grant Date Fair Value	2.13
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 1.55

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	1 Months Ended	3 Months Ended
	Oct. 31, 2011Plaintiff	Mar. 31, 2017USD ($)Rigs	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)
Loss Contingencies [Line Items]
Number of plaintiffs | Plaintiff	2
Case dismissed period		2012-05
Case revised decision period		2013-05
Significant probable or possible environmental contingent liabilities		$ 0
Letters of credit		46,300,000
Rent expense		200,000	$ 300,000
Maximum guarantee of payment of obligations		$ 396,700,000
Guarantee obligations period		2,029
Transportation, processing and marketing expenses of natural gas, condensate and natural gas liquids		$ 26,300,000	21,500,000
Fees related to unutilized capacity commitments		700,000	400,000
Production and Lease Operating Expense		28,934,000	24,451,000
Accrued Liabilities		$ 31,922,000		$ 37,207,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest		52.00%
Charges incurred for unutilized processing capacity		$ 1,600,000	600,000
Capacity Reservation | 2017
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		14,100,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		16,300,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		16,300,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		16,400,000
Capacity Reservation | 2021
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		16,300,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		$ 80,400,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations | Rigs		1
Drilling Commitments | 2017
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs		$ 2,100,000
Minimum gross cost to retain the completion services		500,000
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	$ 500,000
Accrued Liabilities		$ 1,100,000

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Details) $ in Thousands	Mar. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 749
2,018	565
2,019	563
2,020	422
Total	$ 2,299

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands	Mar. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 32,822
2,018	47,350
2,019	47,522
2,020	46,226
2,021	43,285
Thereafter	479,768
Total	$ 696,973

Fee for Unconventional Gas Well

Fee for Unconventional Gas Wells (Details) - Pennsylvania Impact Fee	3 Months Ended
	Mar. 31, 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 shares in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 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	2.2	7.1
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	1.2	1.3
Performance Based Restricted Stock Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	0.4	0.7

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
	Mar. 31, 2017	Mar. 31, 2016
Numerator:
Net Income (Loss) From Continuing Operations	$ 2,683	$ (52,651)
Loss From Discontinued Operations, Net of Income Taxes		(7,490)
Less: Preferred Stock Dividends	(598)	(2,105)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 2,085	$ (62,246)
Denominator:
Weighted Average Common Shares Outstanding - Basic	97,687	56,003
Effect of Dilutive Securities:
Weighted Average Common Shares Outstanding - Diluted	97,687	56,003
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Income (Loss) From Continuing Operations	$ 0.02	$ (0.98)
Basic — Net Loss From Discontinued Operations		(0.13)
Basic - Net Income (Loss) Attributable to Rex Energy Common Shareholders	0.02	(1.11)
Diluted — Net Income (Loss) From Discontinued Operations	0.02	(0.98)
Diluted — Net Loss From Discontinued Operations		(0.13)
Diluted - Net Income (Loss) Attributable to Rex Energy Common Shareholders	$ 0.02	$ (1.11)

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Jun. 30, 2015
Schedule Of Equity Method Investments [Line Items]
Equity Method Investments				$ 0
Production and Lease Operating Expense	$ 28,934,000	$ 24,451,000
RW Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%
Contributions to Equity Method Investments	$ 0	0
Loss on Equity Method Investments	(500,000)	(500,000)
Production and Lease Operating Expense	200,000	$ 200,000
Receivables	0		$ 0
Payables	$ 0		$ 0

Impairment Expense - Additional

Impairment Expense - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$ 1,546	$ 10,641
Butler County, Pennsylvania, and Warrior County, Ohio
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	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		$ 10,600
Butler County | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	700
Marcellus and Utica Shale
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Undeveloped properties, cost	$ 207,800

Exploration Expense - Additiona

Exploration Expense - Additional Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)	Mar. 31, 2016USD ($)Well
Exploration Expense [Line Items]
Exploration Expense	$ 220	$ 936
Geological and Geophysical Type Expenditures
Exploration Expense [Line Items]
Exploration Expense	100	100
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 Finan71

Condensed Consolidating Financial Information - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Principal amount	$ 600.7	$ 601.2

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Details) - USD ($)		Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Jun. 30, 2015
Current Assets
Cash and Cash Equivalents		$ 5,075,000	$ 3,697,000	$ 24,891,000
Accounts Receivable		25,264,000	25,448,000
Taxes Receivable		48,000	211,000
Short-Term Derivative Instruments		3,430,000	1,873,000
Inventory, Prepaid Expenses and Other		2,124,000	2,546,000
Total Current Assets		35,941,000	33,775,000
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		963,481,000	1,053,461,000
Unevaluated Oil and Gas Properties		207,821,000	215,794,000
Other Property and Equipment		21,863,000	21,401,000
Wells and Facilities in Progress		40,740,000	21,964,000
Pipelines		21,262,000	18,029,000
Total Property and Equipment		1,255,167,000	1,330,649,000
Less: Accumulated Depreciation, Depletion and Amortization		(419,500,000)	(475,205,000)
Net Property and Equipment		835,667,000	855,444,000
Equity Method Investments					$ 0
Other Assets		2,495,000	2,492,000
Long-Term Derivative Instruments		3,292,000	2,212,000
Total Assets		877,395,000	893,923,000
Current Liabilities
Accounts Payable		36,838,000	40,712,000
Current Maturities of Long-Term Debt		801,000	764,000
Accrued Liabilities		31,922,000	37,207,000
Short-Term Derivative Instruments		12,801,000	25,025,000
Total Current Liabilities		82,362,000	103,708,000
Long-Term Derivative Instruments		10,265,000	7,227,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		106,573,000	113,785,000
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges	[1],[2]	650,758,000	641,762,000
Discount on Senior Notes, Net		(7,389,000)	(3,601,000)
Other Long-Term Debt		3,849,000	3,409,000
Other Deposits and Liabilities		8,262,000	8,671,000
Future Abandonment Cost		9,465,000	8,736,000
Total Liabilities		864,145,000	883,697,000
Stockholders’ Equity
Preferred Stock		1,000	1,000
Common Stock		96,000	95,000
Additional Paid-In Capital		650,924,000	650,584,000
Accumulated Deficit		(637,771,000)	(640,454,000)
Total Stockholders’ Equity		13,250,000	10,226,000
Total Liabilities and Stockholders’ Equity		877,395,000	893,923,000
Eliminations
Property and Equipment (Successful Efforts Method)
Intercompany Receivables		(1,027,360,000)	(1,035,713,000)
Investment in Subsidiaries – Net		274,745,000	130,362,000
Total Assets		(752,615,000)	(905,351,000)
Current Liabilities
Intercompany Payables		(1,027,360,000)	(1,035,713,000)
Total Liabilities		(1,027,360,000)	(1,035,713,000)
Stockholders’ Equity
Additional Paid-In Capital		(177,144,000)	(177,144,000)
Accumulated Deficit		451,889,000	307,506,000
Total Stockholders’ Equity		274,745,000	130,362,000
Total Liabilities and Stockholders’ Equity		(752,615,000)	(905,351,000)
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents		5,072,000	3,694,000
Accounts Receivable		25,264,000	22,609,000
Short-Term Derivative Instruments		2,875,000	650,000
Inventory, Prepaid Expenses and Other		2,112,000	2,521,000
Total Current Assets		35,323,000	29,474,000
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		963,481,000	1,053,461,000
Unevaluated Oil and Gas Properties		207,821,000	215,794,000
Other Property and Equipment		21,863,000	21,401,000
Wells and Facilities in Progress		40,740,000	21,964,000
Pipelines		21,262,000	18,029,000
Total Property and Equipment		1,255,167,000	1,330,649,000
Less: Accumulated Depreciation, Depletion and Amortization		(419,500,000)	(475,205,000)
Net Property and Equipment		835,667,000	855,444,000
Other Assets		2,495,000	2,492,000
Investment in Subsidiaries – Net		(2,484,000)	(2,388,000)
Long-Term Derivative Instruments		2,329,000	500,000
Total Assets		873,330,000	885,522,000
Current Liabilities
Accounts Payable		36,838,000	40,712,000
Current Maturities of Long-Term Debt		801,000	764,000
Accrued Liabilities		25,311,000	32,328,000
Short-Term Derivative Instruments		12,801,000	25,025,000
Total Current Liabilities		75,751,000	98,829,000
Long-Term Derivative Instruments		10,265,000	7,227,000
Other Long-Term Debt		3,849,000	3,409,000
Other Deposits and Liabilities		8,262,000	8,671,000
Future Abandonment Cost		9,465,000	8,736,000
Intercompany Payables		1,023,697,000	1,032,050,000
Total Liabilities		1,131,289,000	1,158,922,000
Stockholders’ Equity
Additional Paid-In Capital		177,144,000	177,144,000
Accumulated Deficit		(435,103,000)	(450,544,000)
Total Stockholders’ Equity		(257,959,000)	(273,400,000)
Total Liabilities and Stockholders’ Equity		873,330,000	885,522,000
Non-Guarantor Subsidiaries
Current Liabilities
Accrued Liabilities		421,000	421,000
Total Current Liabilities		421,000	421,000
Intercompany Payables		3,663,000	3,663,000
Total Liabilities		4,084,000	4,084,000
Stockholders’ Equity
Accumulated Deficit		(4,084,000)	(4,084,000)
Total Stockholders’ Equity		(4,084,000)	(4,084,000)
Parent Company
Current Assets
Cash and Cash Equivalents		3,000	3,000
Accounts Receivable			2,839,000
Taxes Receivable		48,000	211,000
Short-Term Derivative Instruments		555,000	1,223,000
Inventory, Prepaid Expenses and Other		12,000	25,000
Total Current Assets		618,000	4,301,000
Property and Equipment (Successful Efforts Method)
Intercompany Receivables		1,027,360,000	1,035,713,000
Investment in Subsidiaries – Net		(272,261,000)	(127,974,000)
Long-Term Derivative Instruments		963,000	1,712,000
Total Assets		756,680,000	913,752,000
Current Liabilities
Accrued Liabilities		6,190,000	4,458,000
Total Current Liabilities		6,190,000	4,458,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		106,573,000	113,785,000
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges		650,758,000	641,762,000
Discount on Senior Notes, Net		(7,389,000)	(3,601,000)
Total Liabilities		756,132,000	756,404,000
Stockholders’ Equity
Preferred Stock		1,000	1,000
Common Stock		96,000	95,000
Additional Paid-In Capital		650,924,000	650,584,000
Accumulated Deficit		(650,473,000)	(493,332,000)
Total Stockholders’ Equity		548,000	157,348,000
Total Liabilities and Stockholders’ Equity		$ 756,680,000	$ 913,752,000
[1]	Includes unamortized debt issuance costs of approximately ($17.3) million and ($7.9) million as of March 31, 2017 and December 31, 2016, respectively.
[2]	Includes unamortized deferred gain on debt exchange of approximately $32.8 million and $32.7 million as of March 31, 2017 and December 31, 2016, respectively, as a result of debt exchange transactions completed subsequent to the March 31, 2016 Exchange.

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$ 52,065	$ 25,673
Other Operating Revenue	6	13
TOTAL OPERATING REVENUE	52,071	25,686
OPERATING EXPENSES
Production and Lease Operating Expense	28,934	24,451
General and Administrative Expense	4,534	5,284
(Gain) Loss on Disposal of Assets	(1,834)	11
Impairment Expense	1,546	10,641
Exploration Expense	220	936
Depreciation, Depletion, Amortization and Accretion	15,468	16,511
Other Operating (Income) Expense	(21)	327
TOTAL OPERATING EXPENSES	48,847	58,161
INCOME (LOSS) FROM OPERATIONS	3,224	(32,475)
OTHER INCOME (EXPENSE)
Interest Expense	(9,143)	(13,030)
Gain (Loss) on Derivatives, Net	8,381	4,049
Other Expense	(28)
Gain on Extinguishments of Debt	249
Debt Exchange Expense		(8,480)
TOTAL OTHER EXPENSE	(541)	(17,461)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	2,683	(49,936)
Income Tax Expense		(2,715)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	2,683	(52,651)
Loss From Discontinued Operations, Net of Income Taxes		(7,490)
NET INCOME ATTRIBUTABLE TO REX ENERGY	2,683	(60,141)
Preferred Stock Dividends	(598)	(2,105)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	2,085	(62,246)
Eliminations
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries	(12,702)	38,159
TOTAL OTHER EXPENSE	(12,702)	38,159
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(12,702)	38,159
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		38,159
NET INCOME ATTRIBUTABLE TO REX ENERGY	(12,702)	38,159
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		38,159
Guarantor Subsidiaries
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	52,065	25,673
Other Operating Revenue	6	13
TOTAL OPERATING REVENUE	52,071	25,686
OPERATING EXPENSES
Production and Lease Operating Expense	28,934	24,451
General and Administrative Expense	4,461	5,299
(Gain) Loss on Disposal of Assets	(1,834)	11
Impairment Expense	1,546	10,641
Exploration Expense	220	936
Depreciation, Depletion, Amortization and Accretion	15,468	16,501
Other Operating (Income) Expense	(21)	327
TOTAL OPERATING EXPENSES	48,774	58,166
INCOME (LOSS) FROM OPERATIONS	3,297	(32,480)
OTHER INCOME (EXPENSE)
Interest Expense	(365)	(270)
Gain (Loss) on Derivatives, Net	9,798	4,049
Other Expense	(28)
Income (Loss) From Equity in Consolidated Subsidiaries		(8)
TOTAL OTHER EXPENSE	9,405	3,771
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	12,702	(28,709)
Income Tax Expense		(1,950)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(30,659)
Loss From Discontinued Operations, Net of Income Taxes		(7,492)
NET INCOME ATTRIBUTABLE TO REX ENERGY	12,702	(38,151)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		(38,151)
Non-Guarantor Subsidiaries
OPERATING EXPENSES
Depreciation, Depletion, Amortization and Accretion		10
TOTAL OPERATING EXPENSES		10
INCOME (LOSS) FROM OPERATIONS		(10)
OTHER INCOME (EXPENSE)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(10)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(10)
Loss From Discontinued Operations, Net of Income Taxes		2
NET INCOME ATTRIBUTABLE TO REX ENERGY		(8)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		(8)
Parent Company
OPERATING EXPENSES
General and Administrative Expense	73	(15)
TOTAL OPERATING EXPENSES	73	(15)
INCOME (LOSS) FROM OPERATIONS	(73)	15
OTHER INCOME (EXPENSE)
Interest Expense	(8,778)	(12,760)
Gain (Loss) on Derivatives, Net	(1,417)
Gain on Extinguishments of Debt	249
Debt Exchange Expense		(8,480)
Income (Loss) From Equity in Consolidated Subsidiaries	12,702	(38,151)
TOTAL OTHER EXPENSE	2,756	(59,391)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	2,683	(59,376)
Income Tax Expense		(765)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(60,141)
NET INCOME ATTRIBUTABLE TO REX ENERGY	$ 2,683	(60,141)
Preferred Stock Dividends		(2,105)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ (62,246)

Condensed Consolidating State74

Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ 2,683	$ (60,141)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion	15,468	19,408
(Gain) Loss on Derivatives, Net	(8,381)	(4,049)
Cash Settlements of Derivatives	(3,443)	12,994
Equity-based Compensation Expense	71	(21)
Non-cash Exploration Expenses	11	843
Gain on Disposal of Assets	(1,834)	(30)
Gain on Extinguishments of Debt	(249)
Non-cash Interest Expense related to Debt Restructurings and Exchanges	6,081
Amortization of net Bond Discount and Deferred Debt Issuance Costs		547
Deferred Income Tax Expense		2,092
Impairment Expense	1,546	14,184
Other Non-cash Income	(66)	(29)
Changes in operating assets and liabilities
Accounts Receivable	5,341	(4,873)
Inventory, Prepaid Expenses and Other Assets	422	660
Accounts Payable and Accrued Liabilities	(6,989)	(308)
Other Assets and Liabilities	(139)	(170)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	10,522	(18,893)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	24,329	71
Proceeds from Joint Venture		19,461
Acquisitions of Undeveloped Acreage	(299)	(5,266)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(25,476)	(15,068)
NET CASH USED IN INVESTING ACTIVITIES	(1,446)	(802)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit	21,500	46,500
Repayments of Long-Term Debt and Line of Credit	(28,500)
Repayments of Loans and Other Notes Payable	(131)	(184)
Debt Issuance Costs	(567)	(2,821)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(7,698)	43,495
NET INCREASE IN CASH	1,378	23,800
CASH – BEGINNING	3,697	1,091	$ 1,091
CASH – ENDING	5,075	24,891	3,697
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	(12,702)	38,159
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Impairment Expense		(14,184)
Changes in operating assets and liabilities
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(12,702)	23,975
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries	12,702	(23,975)
NET CASH USED IN INVESTING ACTIVITIES	12,702	(23,975)
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	12,702	(38,151)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion	15,468	19,379
(Gain) Loss on Derivatives, Net	(9,798)	(4,049)
Cash Settlements of Derivatives	(3,443)	12,994
Equity-based Compensation Expense	11	6
Non-cash Exploration Expenses	11	843
Gain on Disposal of Assets	(1,834)	(30)
Deferred Income Tax Expense		1,326
Impairment Expense	1,546	14,184
Other Non-cash Income	(66)	(29)
Changes in operating assets and liabilities
Accounts Receivable	5,174	15,852
Inventory, Prepaid Expenses and Other Assets	410	648
Accounts Payable and Accrued Liabilities	(8,298)	1,921
Other Assets and Liabilities	(139)	(170)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	11,744	24,724
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries	(8,789)	29
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	24,329	71
Proceeds from Joint Venture		19,461
Acquisitions of Undeveloped Acreage	(299)	(5,266)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(25,476)	(15,036)
NET CASH USED IN INVESTING ACTIVITIES	(10,235)	(741)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable	(131)	(184)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(131)	(184)
NET INCREASE IN CASH	1,378	23,799
CASH – BEGINNING	3,694	1,089	1,089
CASH – ENDING	5,072	24,888	3,694
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		(8)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion		29
Deferred Income Tax Expense		1
Changes in operating assets and liabilities
Accounts Receivable		10
Accounts Payable and Accrued Liabilities		21
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		53
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(21)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(32)
NET CASH USED IN INVESTING ACTIVITIES		(53)
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	2,683	(60,141)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
(Gain) Loss on Derivatives, Net	1,417
Equity-based Compensation Expense	60	(27)
Gain on Extinguishments of Debt	(249)
Non-cash Interest Expense related to Debt Restructurings and Exchanges	6,081
Amortization of net Bond Discount and Deferred Debt Issuance Costs		547
Deferred Income Tax Expense		765
Impairment Expense		14,184
Changes in operating assets and liabilities
Accounts Receivable	167	(20,735)
Inventory, Prepaid Expenses and Other Assets	12	12
Accounts Payable and Accrued Liabilities	1,309	(2,250)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	11,480	(67,645)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries	(3,913)	23,967
NET CASH USED IN INVESTING ACTIVITIES	(3,913)	23,967
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit	21,500	46,500
Repayments of Long-Term Debt and Line of Credit	(28,500)
Debt Issuance Costs	(567)	(2,821)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(7,567)	43,679
NET INCREASE IN CASH		1
CASH – BEGINNING	3	2	2
CASH – ENDING	$ 3	$ 3	$ 3

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($)	Apr. 28, 2017	Mar. 31, 2017	Mar. 31, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
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		36 months
Term Loan | Maximum | Scenario, Forecast
Subsequent Event [Line Items]
Net senior secured debt to EBITDAX				325.00%
Term Loan | Minimum | Scenario, Forecast
Subsequent Event [Line Items]
Criteria PDP coverage ratio				165.00%
EBITDAX to interest expense ratio			130.00%	100.00%
EBITDAX to cash interest expense ratio thereafter				130.00%
Subsequent Event | Term Loan
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity	$ 300,000,000
Debt instrument, interest rate	4.00%
Prepayment of outstanding term loan percentage	100.00%
Percentage of prepayment on excess cash flow	50.00%
Subsequent Event | Term Loan | 30 Months After Effective Date
Subsequent Event [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	3.00%
Subsequent Event | Term Loan | 36 Months After Effective Date
Subsequent Event [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	1.00%
Subsequent Event | Term Loan | Adjusted LIBO Rate
Subsequent Event [Line Items]
Debt instrument, floor rate	1.00%
Debt instrument, margin rate	8.75%
Subsequent Event | 8.00% Senior Secured Second Lien Notes due 2020
Subsequent Event [Line Items]
Debt instrument, interest rate	8.00%
Debt instrument, outstanding amount	$ 25,000,000
Subsequent Event | 1.00% Senior Secured Second Lien Notes due 2020
Subsequent Event [Line Items]
Debt instrument, interest rate	1.00%
Subsequent Event | Second Lien Notes | Term Loan
Subsequent Event [Line Items]
Percentage of prepayment on excess cash flow	75.00%
Subsequent Event | Second Lien Notes | Term Loan | Maximum
Subsequent Event [Line Items]
Second lien notes outstanding	$ 287,950,000
Subsequent Event | Secured Term Loan Facility
Subsequent Event [Line Items]
Line of credit facility, current borrowing capacity	143,500,000
Subsequent Event | Secured Delayed Draw Term Loan Facility
Subsequent Event [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