Rex Energy 10-Q 10 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 06, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2,016
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	Accelerated Filer
Entity Common Stock, Shares Outstanding		73,357,014

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents		$ 24,891	$ 1,091
Accounts Receivable		24,315	19,483
Taxes Receivable		18	18
Short-Term Derivative Instruments		29,012	34,260
Inventory, Prepaid Expenses and Other		3,168	3,829
Total Current Assets		81,404	58,681
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,301,479	1,239,430
Unevaluated Oil and Gas Properties		257,697	262,992
Other Property and Equipment		41,028	40,112
Wells and Facilities in Progress		75,514	144,556
Pipelines		16,780	14,024
Total Property and Equipment		1,692,498	1,701,114
Less: Accumulated Depreciation, Depletion and Amortization		(720,998)	(699,899)
Net Property and Equipment		971,500	1,001,215
Other Assets		2,489	2,501
Long-Term Derivative Instruments		8,460	9,534
Total Assets		1,063,853	1,071,931
Current Liabilities
Accounts Payable		42,818	37,874
Current Maturities of Long-Term Debt		9,934	590
Accrued Liabilities		44,296	44,326
Short-Term Derivative Instruments		3,758	2,486
Total Current Liabilities		100,806	85,276
Noncurrent Liabilities
Long-Term Derivative Instruments		6,908	5,556
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		143,294	109,396
Senior Notes, Net of Issuance Costs	[1]	657,511	663,089
Premium on Senior Notes, Net		2,245	2,344
Other Deposits and Liabilities		3,140	3,156
Future Abandonment Cost		43,412	42,883
Total Liabilities		$ 957,316	$ 911,700
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock		$ 1	$ 1
Common Stock		63	54
Additional Paid-In Capital		630,301	623,863
Accumulated Deficit		(523,828)	(463,687)
Total Stockholders’ Equity		106,537	160,231
Total Liabilities and Stockholders’ Equity		$ 1,063,853	$ 1,071,931
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) (Unaudited) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Preferred Stock, par value	$ 1	$ 1
Preferred Stock, shares authorized	100,000	100,000
Preferred Stock, shares issued	12,836	16,100
Preferred Stock, shares outstanding	12,836	16,100
Common Stock, par value	$ 1	$ 1
Common stock, shares authorized	100,000,000	100,000,000
Common Stock, shares issued	66,041,227	55,741,229
Common Stock, shares outstanding	66,041,227	55,741,229

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$ 30,494	$ 54,111
Other Revenue	13	11
TOTAL OPERATING REVENUE	30,507	54,122
OPERATING EXPENSES
Production and Lease Operating Expense	30,146	29,052
General and Administrative Expense	6,063	9,651
(Gain) Loss on Disposal of Asset	(30)	65
Impairment Expense	14,184	7,023
Exploration Expense	993	518
Depreciation, Depletion, Amortization and Accretion	19,408	26,126
Other Operating Expense	329	5,191
TOTAL OPERATING EXPENSES	71,093	77,626
LOSS FROM OPERATIONS	(40,586)	(23,504)
OTHER EXPENSE
Interest Expense	(13,032)	(12,017)
Gain on Derivatives, Net	4,049	17,119
Other Income		34
Debt Exchange Expense	(8,480)
Loss on Equity Method Investments		(203)
TOTAL OTHER INCOME (EXPENSE)	(17,463)	4,933
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(58,049)	(18,571)
Income Tax (Expense) Benefit	(2,092)	92
NET LOSS FROM CONTINUING OPERATIONS	(60,141)	(18,479)
Income From Discontinued Operations, Net of Income Taxes		1,962
NET LOSS	(60,141)	(16,517)
Net Income Attributable to Noncontrolling Interests		1,297
NET LOSS ATTRIBUTABLE TO REX ENERGY	(60,141)	(17,814)
Preferred Stock Dividends	2,105	2,415
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (62,246)	$ (20,229)
Earnings per common share:
Basic – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (0.38)
Basic – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.01
Basic – Net Loss Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (0.37)
Basic – Weighted Average Shares of Common Stock Outstanding	56,003	54,370
Diluted – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (0.38)
Diluted – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.01
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (0.37)
Diluted – Weighted Average Shares of Common Stock Outstanding	56,003	54,370

Consolidated Statement of Chang

Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - 3 months ended Mar. 31, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at Dec. 31, 2015	$ 160,231	$ 54	$ 1	$ 623,863	$ (463,687)
Balance (in shares) at Dec. 31, 2015		55,741	16
Non-Cash Compensation	(29)			(29)
Issuance of Common Stock in Exchange for Debt	6,476	$ 8		6,468
Issuance Of Common Stock In Exchange For Debt (in shares)		8,413
Issuance of Restricted Stock, Net of Forfeitures (in shares)		74
Conversion of Preferred Stock to Common Stock		$ 1		(1)
Conversion of Preferred Stock to Common Stock (in shares)		1,813	(3)
Net Loss	(60,141)				(60,141)
Balance at Mar. 31, 2016	$ 106,537	$ 63	$ 1	$ 630,301	$ (523,828)
Balance (in shares) at Mar. 31, 2016		66,041	13

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (60,141)	$ (16,517)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		203
Non-cash Expenses	497	3,377
Depreciation, Depletion, Amortization and Accretion	19,408	26,165
Gain on Derivatives	(4,049)	(17,119)
Cash Settlements of Derivatives	12,994	11,079
Dry Hole Expense	843	(1)
Deferred Income Tax Expense	2,092
Impairment Expense	14,184	7,023
(Gain) Loss on Sale of Assets	(30)	33
Changes in operating assets and liabilities
Accounts Receivable	(4,873)	10,029
Inventory, Prepaid Expenses and Other Assets	660	328
Accounts Payable and Accrued Liabilities	(308)	(12,929)
Other Assets and Liabilities	(170)	(305)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(18,893)	11,366
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		39
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	71	672
Proceeds from Joint Venture for Reimbursement of Capital Costs	19,461	16,611
Acquisitions of Undeveloped Acreage	(5,266)	(17,459)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(15,068)	(67,013)
NET CASH USED IN INVESTING ACTIVITIES	(802)	(67,150)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(25,761)
Proceeds from Long-Term Debt and Line of Credit	46,500	72,826
Repayments of Loans and Other Notes Payable	(184)	(686)
Debt Issuance Costs	(2,821)	(459)
Dividends Paid on Preferred Stock		(2,415)
Distributions by the Partners of Consolidated Joint Ventures		(531)
NET CASH PROVIDED BY FINANCING ACTIVITIES	43,495	42,974
NET INCREASE (DECREASE) IN CASH	23,800	(12,810)
CASH – BEGINNING	1,091	18,096
CASH – ENDING	24,891	5,286
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	24,891	4,964
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE		322
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	22,479	9,895
Cash Paid for Income Taxes		(502)
NON-CASH ACTIVITIES
Increase (Decrease) in Accrued Liabilities for Capital Expenditures	$ 2,830	$ (602)

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	3 Months Ended
	Mar. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian Basin and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in oil, NGL and natural gas properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. For purposes of compliance with Accounting Standards Update (“ASU”) 2015-3, which we adopted on January 1, 2016, we have reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and approximately $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. In addition, we adopted ASU 2015-17 on January 1, 2016, which eliminates the need to show deferred tax liabilities and assets as current and noncurrent. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero (see Note 5, Recently Issued Accounting Pronouncements 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, 2015. Discontinued Operations Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 3, Discontinued Operations/Assets Held for Sale

Future Abandonment Cost

Future Abandonment Cost	3 Months Ended
	Mar. 31, 2016
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 for each of the three-month periods ended March 31, 2016 and 2015 totaled approximately $0.9 million. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) March 31, 2016 Beginning Balance at January 1, 2016 $ 45,074 Future Abandonment Obligation Incurred 402 Future Abandonment Obligation Settled (361 ) Future Abandonment Obligation Cancelled or Sold (189 ) Future Abandonment Obligation Revision of Estimated Obligation — Future Abandonment Obligation Accretion Expense 856 Total Future Abandonment Cost 1 $ 45,782 1

Discontinued Operations_Assets

Discontinued Operations/Assets Held For Sale	3 Months Ended
	Mar. 31, 2016
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations/Assets Held For Sale	3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE In December 2014, our board of directors approved a formal plan to sell Water Solutions Holdings, LLC (“Water Solutions”), of which we owned a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.8 million. The transaction is recorded as Discontinued Operations. Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. Three Months Ended March 31, ($ in Thousands) 2016 2015 Revenues: Field Services Revenue $ — $ 14,964 Total Operating Revenue — 14,964 Costs and Expenses: General and Administrative Expense — 977 Depreciation, Depletion, Amortization and Accretion — 39 Field Services Operating Expense — 11,289 Gain on Sale of Asset — (32 ) Interest Expense — 191 Other Expense — 103 Total Costs and Expenses — 12,567 Income from Discontinued Operations Before Income Taxes — 2,397 Income Tax Expense — (435 ) Income from Discontinued Operations, net of taxes $ — $ 1,962

Business and Oil and Gas Proper

Business and Oil and Gas Property Acquisitions and Dispositions	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Business and Oil and Gas Property Acquisitions and Dispositions	4. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS Water Solutions As described in Note 3 above, we sold Water Solutions pursuant to a purchase and sale agreement with American Water. ArcLight Capital Partners, LLC On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight will participate and fund 35.0% of the estimated well costs for the designated wells. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. The remainder of the proceeds will be received as additional wells are drilled and completed. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us, leaving ArcLight with a 17.5% working interest. As of March 31, 2016, ArcLight had paid approximately $52.2 million for their interest in wells that have been drilled or are in the process of being drilled. As of March 31, 2016, all wells to be developed with ArcLight had been drilled and completed with four wells remaining to be placed into service. The ArcLight transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized. 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 will participate and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled and completed and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, three of which have already been drilled and completed. We expect total consideration for this transaction to be $175.0 million with $37.1 million committed at closing. As of March 31, 2016, BSP had paid approximately $19.5 million for their interest in wells that had previously been completed. The remainder of the proceeds will be received as additional wells are completed. BSP also has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. In addition, BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of March 31, 2016, 15 of the initial 22 wells were in line and producing, three wells were drilled and awaiting completion and four wells were awaiting pipeline connection. In April 2016, BSP exercised their option to participate in four additional wells to be drilled and completed later in 2016. 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.

Recently Issued Accounting Pron

Recently Issued Accounting Pronouncements	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Recently Issued Accounting Pronouncements	5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. An entity should apply the amendments in this ASU using one of the following two methods: 1) Retrospectively to each prior reporting period presented. 2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications. In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes In February 2016, the FASB issued ASU 2016-02, Leases · A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and · A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating this guidance and do not believe it will have a material impact due to our minimal number of operating leases. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting

Concentrations of Credit Risk

Concentrations of Credit Risk	3 Months Ended
	Mar. 31, 2016
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, 2016, approximately 93.5% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 46.0% of commodity sales. We believe the continued growth in our Appalachian Basin operations will help us to minimize our future risks by diversifying our ratio of oil, NGLs and natural gas sales as well as the quantity of purchasers.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	7. LONG-TERM DEBT Senior Credit Facility We maintain a revolving credit facility evidenced by a credit agreement, dated March 27, 2013 and most recently amended on March 13, 2016 (the “Senior Credit Facility”). As of March 31, 2016, the borrowing base under the Senior Credit Facility was $200.0 million; however, the Senior Credit Facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a subfacility exists for up to $60.0 million of letters of credit. Effective April 1, 2016, our borrowing base was further reduced to $190.0 million in connection with our senior note exchange described below. As of March 31, 2016, loans made under the Senior Credit Facility were set to mature on September 12, 2019. Our borrowing base is re-determined at least twice per year with the next re-determination scheduled to occur on or about July 1, 2016. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of March 31, 2016, we had $158.0 million outstanding, approximately $41.0 million in outstanding undrawn letters of credit and approximately $1.0 million available to borrow. There were $111.5 million borrowings outstanding as of December 31, 2015. Our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million, with any excess to be used to pay down the outstanding Senior Credit Facility balance, however we retain the right to draw on the Senior Credit Facility so long as there are amounts available under our borrowing base. The Senior Credit Facility requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and maximum net senior secured debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank 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 activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of March 31, 2016 was approximately 0.6 to 1.0. Due to our expectation that we would not be in compliance with the current ratio we previously received a waiver of this requirement from the lenders for the period ended March 31, 2016. We expect to be in compliance with the current ratio covenant at June 30, 2016 and beyond. Additionally, as of the last day of any fiscal quarter, our ratio of net senior secured debt to EBITDAX for the trailing twelve months must not exceed 2.75 to 1.0. Our maximum net senior secured debt to EBITDAX ratio was lowered to 2.75 to 1.0 from 3.0 to 1.0 in connection with our senior note exchange described below. Our ratio of net senior secured debt to EBITDAX as of March 31, 2016 was approximately 2.1 to 1.0. In order to improve our liquidity positions to meet the financial requirements under our Senior Credit Facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions including (i) debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital, (vi) adding hedging positions, and (vii) in- and out-of-court restructuring. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet certain 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 and a new effective interest rate has been established. In exchange for $324.0 million in aggregate principal amount of the 2022 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) $633.7 million aggregate principal amount of New Notes and (ii) issued 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 the 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 payable in cash thereafter. Interest payments are due on April 1 and October 1 of each year, beginning on October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $8.5 million in third-party debt issuance costs. These costs were recorded as Debt Exchange Expense in our Statement of Operations for the three-month period ended March 31, 2016. 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 New Notes from the holders. Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets. The Senior Notes 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 Senior Notes 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 2.25:1. As of March 31, 2016, our Fixed Charge Coverage Ratio was 1.00. We expect our Fixed Charge Coverage Ratio to improve in 2016 based on our projections of decreased interest expense related to the New Notes. As of March 31, 2016, we were limited to incurring an additional $68.9 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. As of March 31, 2016 and December 31, 2015, we had recorded on our Consolidated Balance Sheets approximately $2.2 million and $2.3 million, respectively, of a net premium related to the Senior Notes. The amortization of our net premium during the three months ended March 31, 2016, which follows the effective interest method, was approximately $0.1 million and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations. . In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at March 31, 2016 and December 31, 2015: ($ in Thousands) March 31, 2016 (Unaudited) December 31, 2015 Senior Notes, Net of Issuance Costs (a) $ 657,511 $ 663,089 Premium on Senior Notes, Net 2,245 2,344 Senior Line of Credit, Net of Issuance Costs (b)(c) 152,794 109,396 Capital Leases and Other Obligations(c) 434 618 Total Debt 812,984 775,447 Less Current Portion of Long-Term Debt (9,934 ) (590 ) Total Long-Term Debt $ 803,050 $ 774,857 (a) Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively. (b) Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 2016 and December 31, 2015, respectively. (c) 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, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5% The following is the principal maturity schedule for debt outstanding as of March 31, 2016: 2016 $ 9,906 2017 28 2018 — 2019 148,500 2020 652,658 Thereafter 15,865 Total (a) $ 826,957 (a) Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs

Derivative Instruments And Fair

Derivative Instruments And Fair Value Measurements	3 Months Ended
	Mar. 31, 2016
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, 2016 and December 31, 2015, 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 received net cash settlements of $13.0 As of March 31, 2016, we had approximately 100.0% of our annualized oil production hedged through the remainder of 2016, over 100.0% and 50.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 40.0% our annualized NGL production hedged through the remainder of 2016. 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 oil and gas production. 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, 2016, and December 31, 2015, we had $158.0 million and $111.5 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $675.0 million of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt As of March 31, 2016 and December 31, 2015, 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. During the three months ended March 31, 2015, we received cash payments of approximately $0.5 million related to our interest rate swaptions. The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2016 and 2015: For the Three Months Ended March 31, ($ in Thousands) 2016 2015 Oil $ 325 $ 2,876 Natural Gas 5,363 13,600 NGLs (1,621 ) 435 Refined Products (18 ) (55 ) Interest Rate — 263 Gain on Derivatives, Net $ 4,049 $ 17,119 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 asset of approximately $26.8 million and $35.8 million at March 31, 2016 and December 31, 2015, respectively. Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2016 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2016 - Collars 445,750 Bbls $ — $ 38.72 $ 50.28 $ — $ 662 2016 - Three-Way Collars 225,000 Bbls 31.20 41.40 49.60 — 340 2016 - Cap Swaps 60,000 Bbls 30.00 — — 44.00 42 730,750 Bbls $ 1,044 Natural Gas 2016 - Swaps 14,090,000 Mcf — — — 2.95 $ 10,341 2016 - Swaptions 900,000 Mcf — — — 3.15 767 2016 - Cap Swaps 4,050,000 Mcf 2.90 — — 3.48 1,102 2016 - Collars 2,250,000 Mcf — 2.70 3.10 — 973 2016 - Three-Way Collars 8,480,000 Mcf 2.31 2.95 3.55 — 5,054 2016 - Put Spreads 9,470,000 Mcf 2.50 3.26 — — 808 2016 - Basis Swaps - Dominion South 17,665,000 Mcf — — — (0.89 ) (1,879 ) 2017 - Swaps 960,000 Mcf — — — 3.60 903 2017 - Swaptions 0 Mcf — — — — (263 ) 2017 - Cap Swaps 5,700,000 Mcf 2.65 — — 3.20 951 2017 - Three-Way Collars 16,300,000 Mcf 2.33 3.02 3.89 — 5,066 2017 - Calls 3,000,000 Mcf — — 3.64 — (753 ) 2017 - Basis Swaps - Dominion South 4,550,000 Mcf — — — (0.83 ) (1,092 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (513 ) 2018 - Swaps 960,000 Mcf — — — 3.60 903 2018 - Swaptions 0 Mcf — — — — (191 ) 2018 - Cap Swaps 1,800,000 Mcf 3.30 — — 4.05 1,060 2018 - Three-Way Collars 7,875,000 Mcf 2.29 2.88 3.56 — 1,046 2018 - Calls 5,810,000 Mcf — — 3.97 — (328 ) 2018 - Basis Swaps - Dominion South 6,400,000 Mcf — — — (0.83 ) (1,092 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (513 ) 2019 - Basis Swaps - Dominion South 7,300,000 Mcf — — — (0.83 ) (1,092 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.83 ) (1,092 ) 154,080,000 Mcf $ 20,166 NGLs 2016 - C3+ NGL Swaps 1,038,000 Bbls — — — 30.66 $ 6,006 2016 - Ethane Swaps 165,000 Bbls — — — 8.82 155 2017 - C3+ NGL Swaps 468,000 Bbls — — — 20.16 (287 ) 1,671,000 Bbls $ 5,874 Refined Product (Heating Oil) 2016 - Swaps 9,000 Bbls $ — $ — $ — $ 84.00 $ (278 ) 9,000 Bbls $ (278 ) 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, 2016 and December 31, 2015 is summarized below: March 31, December 31, ($ in Thousands) 2016 2015 Short-Term Derivative Assets: Crude Oil—Collars $ 662 $ 1,078 Crude Oil—Deferred Put Spread 42 852 Crude Oil—Three-Way Collars 616 577 NGL—Swaps 6,579 10,250 Natural Gas—Swaps 10,576 9,010 Natural Gas—Cap Swaps 1,638 1,977 Natural Gas—Basis Swaps — 70 Natural Gas—Three-Way Collars 6,326 6,183 Natural Gas—Collars 973 1,728 Natural Gas—Swaption 792 798 Natural Gas—Put Spread 808 1,737 Total Short-Term Derivative Assets $ 29,012 $ 34,260 Long-Term Derivative Assets: NGL—Swaps $ 185 $ 344 Natural Gas—Cap Swaps 1,855 2,294 Natural Gas—Swaps 1,580 1,593 Natural Gas—Basis Swaps — 195 Natural Gas—Three-Way Collars 4,840 5,108 Total Long-Term Derivative Assets $ 8,460 $ 9,534 Total Derivative Assets $ 37,472 $ 43,794 Short-Term Derivative Liabilities: Crude Oil—Three-Way Collars (276 ) — NGL—Swaps (490 ) — Refined Product—Swaps (278 ) (376 ) Natural Gas—Three-Way Collars — (31 ) Natural Gas—Basis Swaps (2,280 ) (1,585 ) Natural Gas—Call (189 ) — Natural Gas—Swaption (46 ) (202 ) Natural Gas—Swaps (9 ) (292 ) Natural Gas—Cap Swaps (190 ) — Total Short - Term Derivative Liabilities $ (3,758 ) $ (2,486 ) Long-Term Derivative Liabilities: NGL—Swaps (400 ) — Natural Gas—Swaption (433 ) (297 ) Natural Gas—Basis Swaps (4,993 ) (4,186 ) Natural Gas—Call (892 ) (989 ) Natural Gas—Cap Swaps (190 ) — Natural Gas—Three-Way Collars — (84 ) Total Long-Term Derivative Liabilities $ (6,908 ) $ (5,556 ) Total Derivative Liabilities $ (10,666 ) $ (8,042 ) Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of March 31, 2016 and December 31, 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. Our Level 3 fair value measurements are comprised of our natural gas basis swap contracts. The fair values recorded as of March 31, 2016 and December 31, 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of March 31, 2016 and December 31, 2015 are included in the table below. As of March 31, 2016 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.30) - ($1.02) $ (0.85 ) $ (6,247 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.09) - ($0.13) $ (0.13 ) $ (1,026 ) As of December 31, 2015 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.27) - ($1.08) $ (0.74 ) $ (5,468 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.05) - ($0.17) $ (0.12 ) $ (38 ) The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three months ended March 31, 2016 and for the year ended December 31, 2015, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at March 31, 2016 Using: ($ in Thousands) Total Carrying Value as of March 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 $ 26,806 $ — $ 34,079 $ (7,273 ) Fair Value Measurements at December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 ) Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations. The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair values attributable to our oil derivatives as of March 31, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, 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, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of March 31, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments. The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2016 and 2015: Three Months Ended March 31, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value (2,037 ) (1,955 ) Purchases — — Settlements Received 270 409 Ending Balance of Level 3 $ (7,273 ) $ (205 ) Changes in fair value on our Level 3 commodity derivative contracts outstanding for each of the three months ended March 31, 2016 and 2015, resulted in decreases of approximately $2.0 million. This amount has been included in Gain on Derivatives, Net in our Consolidated Statements of Operations. Future Abandonment Cost We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: March 31, 2016 December 31, 2015 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 657,511 $ 78,715 $ 663,089 $ 137,402 Secured Line of Credit 152,794 152,794 109,396 109,396 Capital Leases and Other Obligations 434 427 618 606 Total $ 810,739 $ 231,936 $ 773,103 $ 247,404 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, 2016, we recorded an other than temporary impairment of $14.2 million 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 2 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, 2016
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, ($ in Thousands) 2016 2015 Income (Expense) Benefit $ (2,092 ) $ 92 Effective Tax Rate -3.6 % 0.5 % For the three months ended March 31, 2016 and 2015, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due to the recording of a valuation allowance. As of March 31, 2016 and 2015, we had a significant level of estimated future tax benefits that, given our past and future expectations of net losses, we do not expect to be able to fully utilize, thus limiting our ability to recognize future tax benefits. As a result of the Exchange, we generated approximately $543.2 million in cancellation of debt income as calculated by comparing the fair value of the New Notes and the face value of the Existing Notes. We expect to offset this income by utilizing our net operating loss carryforwards, resulting in a projected alternative minimum tax payment of approximately $5.5 million. Income tax payments made during the three months ended March 31, 2016 and 2015 were negligible. We received tax refunds during the three months ended March 31, 2015 of approximately $0.5 million.

Capital Stock

Capital Stock	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Capital Stock	10. CAPITAL STOCK Common Stock We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of March 31, 2016 and December 31, 2015, shares of common stock issued and outstanding totaled 66,041,227 and 55,741,229, respectively. Preferred Stock As of March 31, 2016 and December 31, 2015, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”) issued and outstanding totaled 12,836 and 16,100, respectively. During the first quarter of 2016, approximately 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. 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 has been declared by our board of directors in 2016. As of March 31, 2016 accumulated dividends in arrears totaled $2.1 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulated dividends are added to our Net Loss in the determination of Loss Attributable to Common Shareholders and related loss per share calculations. In 2015, we paid quarterly cash dividends of $150.00 per share for the periods of November 15, 2014 to February 15, 2015, February 15, 2015 to May 15, 2015, May 15, 2015 to August 15, 2015, and August 15, 2015 to November 15, 2015, respectively, each in the aggregate amount of $2.4 million. If we do not pay dividends for six consecutive quarterly periods, 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, 2016
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-month period ended March 31, 2016, we issued 851,422 options to purchase shares of our common stock to 29 employees. We issued 80,000 options to purchase shares of our common stock for the three months ended March 31, 2015. Stock-based compensation expense relating to stock options outstanding for the three months ended March 31, 2016 and 2015 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. There were no stock options exercised for the three months ended March 31, 2016 and 2015. There was no tax benefit for the three-month periods ended March 31, 2016 and 2015. A summary of the status of our issued and outstanding stock options as of March 31, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 3/31/16 Weighted-Average Exercise Price Number Exercisable At 3/31/16 Weighted-Average Exercise Price $ 1.69 851,422 $ 1.69 — $ — $ 4.05 40,000 $ 4.05 — $ — $ 4.90 40,000 $ 4.90 3,333 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 11.87 3,500 $ 11.87 3,500 $ 11.87 $ 13.19 50,000 $ 13.19 50,000 $ 13.19 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,295,094 $ 4.41 367,005 $ 10.72 The weighted average remaining contractual term for options outstanding at March 31, 2016 was 5.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at March 31, 2016 was 1.9 years and there was no aggregate intrinsic value. As of March 31, 2016, unrecognized compensation expense related to stock options was $0.5 million. Restricted Stock Awards During the three-month period ended March 31, 2016, the Compensation Committee approved the issuance of an aggregate of 420,901 shares of restricted common stock to 22 employees. During the three-month period ended March 31, 2015, the Compensation Committee approved the issuance of an aggregate of 1,336,295 shares of restricted stock to 126 employees and one non-employee contractor. 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. 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 Compensation expense associated with restricted stock awards was negligible and $3.0 million for the three-month period ended March 31, 2016 and 2015, respectively. During the first quarter of 2016, 235,573 performance stock awards were forfeited due to not meeting specified targets, which resulted in a one-time reduction to expense of approximately $1.5 million. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of March 31, 2016, total unrecognized compensation cost related to restricted common stock grants was approximately $3.6 million, which will be recognized over a weighted average period of 1.5 years. A summary of the restricted stock activity for the three months ended March 31, 2016 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 420,901 1.67 Forfeitures (346,876 ) 7.83 Vested (142,516 ) 12.76 Restricted stock awards, as of March 31, 2016 2,410,917 $ 4.86

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2016
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. 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, 2015. 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, 2016, we know of no significant probable or possible environmental contingent liabilities. Letters of Credit At March 31, 2016, we had posted $41.0 million in various letters of credit to secure our drilling and related operations. Lease Commitments As of March 31, 2016, 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, 2016 and 2015, was approximately $0.3 million and $0.2 million, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2016 $ 766 2017 991 2018 565 2019 563 2020 422 Thereafter — Total $ 3,307 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 process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $10.9 million in 2016, $16.5 million in 2017, $16.5 million in 2018, $16.5 million in 2019, $16.6 million in 2020 and $97.9 million thereafter, assuming our average net revenue interest in the region of approximately 53%. Charges incurred for unutilized processing capacity with MarkWest during the three-month period ended March 31, 2016 and 2015 were $0.6 million and $0.2 million, respectively. Operational Commitments We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $1.7 million in 2016, $2.3 million in 2017 and $0.3 million in 2018 , Natural Gas Gathering, Processing and Sales Agreements During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $418.0 million through 2021. For the three months ended March 31, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $21.5 million and $18.9 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, 2016 and 2015, we incurred approximately $0.4 million and $0.9 million, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2016 $ 24,715 2017 49,357 2018 53,456 2019 52,904 2020 51,697 Thereafter 458,695 Total $ 690,824 Pennsylvania Impact Fee In 2012, Pennsylvania state legislators 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, 2016 and 2015, we recorded expense of approximately $0.5 million and $0.6 million, respectively.

Earnings Per Common Share

Earnings Per Common Share	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Common Share	13. EARNINGS PER COMMON SHARE Basic 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, 2016 and March 31, 2015, we excluded stock options to purchase 1.3 million shares and 0.5 million shares of our common stock, respectively, due to our Net Loss from Continuing Operations. For the three months ended March 31, 2016 and 2015, we excluded performance-based restricted stock of 0.7 million shares and 1.3 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: 2016 2015 Net Loss From Continuing Operations $ (60,141 ) $ (18,479 ) Net Income From Discontinued Operations, Less Noncontrolling Interests — 665 Less: Preferred Stock Dividends (2,105 ) (2,415 ) Net Loss Attributable to Common Shareholders $ (62,246 ) $ (20,229 ) Denominator: Weighted Average Common Shares Outstanding - Basic 56,003 54,370 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 56,003 54,370 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) — Net Income From Discontinued Operations — 0.01 — Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 ) Diluted — Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) — Net Income From Discontinued Operations — 0.01 — Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 )

Equity Method Investments

Equity Method Investments	3 Months Ended
	Mar. 31, 2016
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 Appalachian Basin operations. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering. We did not make any capital contributions to RW Gathering during the first three months of 2016 and 2015. During each of the three months ended March 31, 2016 and March 31, 2015, RW Gathering incurred net losses from continuing operations of $0.5 million. The loss incurred was 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 each of the three-month periods ended March 31, 2016 and 2015, 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, 2016 and December 31, 2015, there were no receivables or payables due between RW Gathering and us.

Impairment Expense

Impairment Expense	3 Months Ended
	Mar. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment Expense	15. IMPAIRMENT EXPENSE For the three months ended March 31, 2016 and 2015, impairment expenses incurred were approximately $14.2 million and $7.0 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first three months of 2016 included proved property impairments of approximately $3.5 million attributable to conventional oil properties in the Illinois Basin. In addition to the proved properties, we also incurred unproved property impairments of approximately $10.7 million related to unconventional assets in the Appalachian Basin. 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. The primary reason for the decrease in estimated future cash flows of our assets is attributable to the continued depression of current and estimated future commodity prices as of March 31, 2016. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices continue to decline, which may result in our incurrence of additional impairment expense. As of March 31, 2016, we continued to carry the costs of undeveloped properties of approximately $257.7 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans. The expenses incurred during the first quarter of 2015 included approximately $4.0 million related to proved properties in our non-operated dry gas region of Clearfield County, Pennsylvania. The remaining $3.0 million of impairment expense in the first quarter of 2015 was incurred in relation to undeveloped leases that expired or were expected to expire without being developed, primarily in the Appalachian Basin.

Exploration Expense

Exploration Expense	3 Months Ended
	Mar. 31, 2016
Extractive Industries [Abstract]
Exploration Expense	16. EXPLORATION EXPENSE For the three months ended March 31, 2016 and 2015, we incurred approximately $1.0 million and $0.5 million, respectively, in exploration expenses. Approximately $0.2 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and the remaining $0.8 million was due to two exploratory wells that were abandoned at various stages that resulted in dry hole expense in the Appalachian Basin. The expense incurred in 2015 was due to geological and geophysical type expenditures.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	3 Months Ended
	Mar. 31, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of March 31, 2016, we had an aggregate of $675.0 million of outstanding Senior Notes, as shown in Note 7, Long-Term Debt — Rex Energy I, LLC — Rex Energy Operating Corporation — Rex Energy IV, LLC — PennTex Resources Illinois, Inc. — R.E. Gas Development, LLC The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of March 31, 2016, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, the condensed consolidating statements of operations for each of the three-month periods ended March 31, 2016 and 2015, and the condensed consolidating statements of cash flows for each of the three-month periods ended March 31, 2016 and 2015. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF MARCH 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 24,888 $ — $ 3 $ — $ 24,891 Accounts Receivable 24,252 16 47 — 24,315 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 29,012 — — — 29,012 Inventory, Prepaid Expenses and Other 3,156 — 12 — 3,168 Total Current Assets 81,308 16 80 — 81,404 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,300,678 801 — 1,301,479 Unevaluated Oil and Gas Properties 257,697 — — — 257,697 Other Property and Equipment 40,133 895 — — 41,028 Wells and Facilities in Progress 75,269 245 — — 75,514 Pipelines 16,780 — — — 16,780 Total Property and Equipment 1,690,557 1,941 — — 1,692,498 Less: Accumulated Depreciation, Depletion and Amortization (720,100 ) (898 ) — — (720,998 ) Net Property and Equipment 970,457 1,043 — — 971,500 Other Assets 2,489 — — — 2,489 Intercompany Receivables — — 1,095,371 (1,095,371 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 8,460 — — — 8,460 Total Assets $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 42,818 $ — $ — $ — $ 42,818 Current Maturities of Long-Term Debt 434 — 9,500 — 9,934 Accrued Liabilities 32,709 20 11,567 44,296 Short-Term Derivative Instruments 3,758 — — — 3,758 Total Current Liabilities 79,719 20 21,067 — 100,806 Long-Term Derivative Instruments 6,908 — — — 6,908 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs — — 143,294 — 143,294 Senior Notes, Net of Issuance Costs — — 657,511 — 657,511 Premium on Senior Notes – Net — — 2,245 — 2,245 Other Deposits and Liabilities 3,140 — — — 3,140 Future Abandonment Cost 42,964 448 — — 43,412 Intercompany Payables 1,090,818 4,553 — (1,095,371 ) — Total Liabilities 1,223,549 5,021 824,117 (1,095,371 ) 957,316 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 63 — 63 Additional Paid-In Capital 177,144 — 630,301 (177,144 ) 630,301 Accumulated Earnings (Deficit) (340,367 ) (3,962 ) (487,005 ) 307,506 (523,828 ) Total Stockholders’ Equity (163,223 ) (3,962 ) 143,360 130,362 106,537 Total Liabilities and Stockholders’ Equity $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 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 Oil, Natural Gas and NGL Sales $ 30,463 $ 31 $ — $ — $ 30,494 Other Revenue 13 — — — 13 TOTAL OPERATING REVENUE 30,476 31 — — 30,507 OPERATING EXPENSES Production and Lease Operating Expense 30,121 25 — — 30,146 General and Administrative Expense 6,068 9 (14 ) — 6,063 Gain on Disposal of Asset (30 ) — — — (30 ) Impairment Expense 14,184 — — — 14,184 Exploration Expense 993 — — — 993 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Other Operating Income 329 — — — 329 TOTAL OPERATING EXPENSES 71,044 63 (14 ) — 71,093 INCOME (LOSS) FROM OPERATIONS (40,568 ) (32 ) 14 — (40,586 ) OTHER INCOME (EXPENSE) Interest Expense (273 ) — (12,759 ) — (13,032 ) Gain on Derivatives, Net 4,049 — — — 4,049 Debt Exchange Expense — — (8,480 ) — (8,480 ) Income (Loss) From Equity in Consolidated Subsidiaries (25 ) 25 (38,151 ) 38,151 — TOTAL OTHER INCOME (EXPENSE) 3,751 25 (59,390 ) 38,151 (17,463 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (36,817 ) (7 ) (59,376 ) 38,151 (58,049 ) Income Tax Expense (1,326 ) (1 ) (765 ) — (2,092 ) NET INCOME (LOSS) (38,143 ) (8 ) (60,141 ) 38,151 (60,141 ) Preferred Stock Dividends — — 2,105 — 2,105 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (38,143 ) $ (8 ) $ (62,246 ) $ 38,151 $ (62,246 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (38,143 ) $ (8 ) $ (60,141 ) $ 38,151 $ (60,141 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (30 ) — 527 — 497 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Gain on Derivatives (4,049 ) — — — (4,049 ) Cash Settlements of Derivatives 12,994 — — — 12,994 Dry Hole Expense 843 — — — 843 Gain on Sale of Asset (30 ) — — — (30 ) Deferred Income Tax Expense 1,326 1 765 — 2,092 Impairment Expense 14,184 — 14,184 (14,184 ) 14,184 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 1,922 21 (2,251 ) — (308 ) Other Assets and Liabilities (170 ) — — — (170 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,726 53 (67,639 ) 23,967 (18,893 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27 (21 ) 23,961 (23,967 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 71 — — — 71 Proceeds from Joint Venture for Reimbursement of Capital Costs 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 (743 ) (53 ) 23,961 (23,967 ) (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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 19,423 11 49 — 19,483 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,804 — 25 — 3,829 Total Current Assets 58,576 11 94 — 58,681 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,245,626 774 — (6,970 ) 1,239,430 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 39,217 895 — — 40,112 Wells and Facilities in Progress 144,587 239 — (270 ) 144,556 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,708,583 1,908 — (9,377 ) 1,701,114 Less: Accumulated Depreciation, Depletion and Amortization (702,537 ) (880 ) — 3,518 (699,899 ) Net Property and Equipment 1,006,046 1,028 — (5,859 ) 1,001,215 Deferred Financing Costs and Other Assets—Net 2,501 — — — 2,501 Intercompany Receivables — — 1,070,548 (1,070,548 ) — Investment in Subsidiaries – Net (1,907 ) — 243,331 (241,424 ) — Long-Term Derivative Instruments 9,534 — — — 9,534 Total Assets $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 37,874 $ — $ — $ — $ 37,874 Current Maturities of Long-Term Debt 590 — — — 590 Accrued Liabilities 32,601 — 11,725 — 44,326 Short-Term Derivative Instruments 2,486 — — — 2,486 Total Current Liabilities 73,551 — 11,725 — 85,276 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 28 — 109,368 — 109,396 Senior Notes, Net of Issuance Costs — — 663,089 — 663,089 Premium on Senior Notes – Net — — 2,344 — 2,344 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 42,443 440 — — 42,883 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,830 892 786,526 (1,070,548 ) 911,700 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,143 — 619,777 (173,057 ) 623,863 Accumulated Earnings (Deficit) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 54,000 $ 111 $ — $ — $ 54,111 Other Revenue 11 — — — 11 TOTAL OPERATING REVENUE 54,011 111 — — 54,122 OPERATING EXPENSES Production and Lease Operating Expense 29,014 38 — — 29,052 General and Administrative Expense 6,659 16 2,976 — 9,651 Loss on Disposal of Asset 65 — — — 65 Impairment Expense 7,012 11 — — 7,023 Exploration Expense 518 — — — 518 Depreciation, Depletion, Amortization and Accretion 26,292 69 — (235 ) 26,126 Other Operating Expense 5,191 — — — 5,191 TOTAL OPERATING EXPENSES 74,751 134 2,976 (235 ) 77,626 INCOME (LOSS) FROM OPERATIONS (20,740 ) (23 ) (2,976 ) 235 (23,504 ) OTHER INCOME (EXPENSE) Interest Expense (58 ) — (11,959 ) — (12,017 ) Gain on Derivatives, Net 16,856 — 263 — 17,119 Other Expense 34 — — — 34 Loss From Equity Method Investments (203 ) — — — (203 ) Income (Loss) From Equity in Consolidated Subsidiaries (23 ) 23 (3,214 ) 3,214 — TOTAL OTHER INCOME (EXPENSE) 16,606 23 (14,910 ) 3,214 4,933 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (4,134 ) — (17,886 ) 3,449 (18,571 ) Income Tax Benefit 20 — 72 — 92 INCOME (LOSS) FROM CONTINUING OPERATIONS (4,114 ) — (17,814 ) 3,449 (18,479 ) Loss From Discontinued Operations, Net of Income Tax — 2,826 — (864 ) 1,962 Net Income (Loss) (4,114 ) 2,826 (17,814 ) 2,585 (16,517 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 1,297 — — 1,297 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (4,114 ) $ 1,529 $ (17,814 ) $ 2,585 $ (17,814 ) Preferred Stock Dividends — — 2,415 — 2,415 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (4,114 ) $ 1,529 $ (20,229 ) $ 2,585 $ (20,229 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (4,114 ) $ 2,826 $ (17,814 ) $ 2,585 $ (16,517 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss From Equity Method Investments 203 — — — 203 Non-Cash Expenses (70 ) 44 3,403 — 3,377 Depreciation, Depletion, Amortization and Accretion 26,292 1,480 — (1,607 ) 26,165 Gain on Derivatives (16,856 ) — (263 ) — (17,119 ) Cash Settlements of Derivatives 10,579 — 500 — 11,079 Dry Hole Expense (1 ) — — — (1 ) (Gain) Loss on Sale of Asset 65 (32 ) — — 33 Impairment Expense 7,012 11 — — 7,023 Changes in operating assets and liabilities Accounts Receivable 10,437 (1,087 ) 428 251 10,029 Inventory, Prepaid Expenses and Other Assets 712 (322 ) (62 ) — 328 Accounts Payable and Accrued Liabilities (12,518 ) (2,496 ) 2,336 (251 ) (12,929 ) Other Assets and Liabilities (199 ) (133 ) 27 — (305 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 21,542 291 (11,445 ) 978 11,366 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27,192 (1,688 ) (23,681 ) (1,823 ) — Proceeds from Joint Venture Acreage Management 39 — — — 39 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 217 455 — — 672 Proceeds from Joint Venture for Reimbursement of Capital Costs 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (17,454 ) (5 ) — — (17,459 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (60,719 ) (7,139 ) — 845 (67,013 ) NET CASH USED IN INVESTING ACTIVITIES (34,114 ) (8,377 ) (23,681 ) (978 ) (67,150 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 18,826 54,000 — 72,826 Repayments of Long-Term Debt and Lines of Credit — (9,761 ) (16,000 ) — (25,761 ) Repayments of Loans and Other Notes Payable (392 ) (294 ) — — (686 ) Debt Issuance Costs — — (459 ) — (459 ) Dividends Paid — — (2,415 ) — (2,415 ) Distributions by the Partners of Consolidated Subsidiaries — (531 ) — — (531 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (392 ) 8,240 35,126 — 42,974 NET INCREASE IN CASH (12,964 ) 154 — — (12,810 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH - ENDING $ 5,014 $ 267 $ 5 $ — $ 5,286

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	18. SUBSEQUENT EVENTS Debt and Preferred Stock Exchanges During April 2016, we completed two privately negotiated exchanges of shares of our common stock for outstanding 2020 Notes, 2022 Notes, New Notes and our Series A Preferred Stock. In total, we exchanged approximately $17.2 million of 2020 Notes, $9.7 million of 2022 Notes, $2.2 million of New Notes and $13.8 million in face value of the Series A Preferred Stock for approximately 7.1 million shares of our common stock. In each transaction, the holders waived all accrued and unpaid interest. The shares of our common stock were issued under Section 3(a)(9) of the Securities Act of 1933, as amended. Borrowing Base Reduction In conjunction with the Exchange, effective April 1, 2016, we amended certain terms of our Senior Credit Facility including the reduction of our borrowing base from $200.0 million to $190.0 million effective April 1, 2016. As of March 31, 2016, we had approximately $158.0 million outstanding under our Senior Credit Facility and $41.0 million of undrawn letters of credit. On April 1, 2016, we paid down borrowings under our Senior Credit Facility by $9.5 million on April 1, 2016 to be in compliance with the amendment. This amount was recorded as Current Maturities of Long-Term Debt on our Consolidated Balance Sheet as of March 31, 2016.

Recently Issued Accounting Pr25

Recently Issued Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Recently Issued Accounting Pronouncements	In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. An entity should apply the amendments in this ASU using one of the following two methods: 1) Retrospectively to each prior reporting period presented. 2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications. In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes In February 2016, the FASB issued ASU 2016-02, Leases · A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and · A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating this guidance and do not believe it will have a material impact due to our minimal number of operating leases. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting

Future Abandonment Cost (Tables

Future Abandonment Cost (Tables)	3 Months Ended
	Mar. 31, 2016
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, 2016 Beginning Balance at January 1, 2016 $ 45,074 Future Abandonment Obligation Incurred 402 Future Abandonment Obligation Settled (361 ) Future Abandonment Obligation Cancelled or Sold (189 ) Future Abandonment Obligation Revision of Estimated Obligation — Future Abandonment Obligation Accretion Expense 856 Total Future Abandonment Cost 1 $ 45,782 1

Discontinued Operations_Asset27

Discontinued Operations/Assets Held For Sale (Tables)	3 Months Ended
	Mar. 31, 2016
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such 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. Three Months Ended March 31, ($ in Thousands) 2016 2015 Revenues: Field Services Revenue $ — $ 14,964 Total Operating Revenue — 14,964 Costs and Expenses: General and Administrative Expense — 977 Depreciation, Depletion, Amortization and Accretion — 39 Field Services Operating Expense — 11,289 Gain on Sale of Asset — (32 ) Interest Expense — 191 Other Expense — 103 Total Costs and Expenses — 12,567 Income from Discontinued Operations Before Income Taxes — 2,397 Income Tax Expense — (435 ) Income from Discontinued Operations, net of taxes $ — $ 1,962

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Components of Long-Term Debt and Lines of Credit	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at March 31, 2016 and December 31, 2015: ($ in Thousands) March 31, 2016 (Unaudited) December 31, 2015 Senior Notes, Net of Issuance Costs (a) $ 657,511 $ 663,089 Premium on Senior Notes, Net 2,245 2,344 Senior Line of Credit, Net of Issuance Costs (b)(c) 152,794 109,396 Capital Leases and Other Obligations(c) 434 618 Total Debt 812,984 775,447 Less Current Portion of Long-Term Debt (9,934 ) (590 ) Total Long-Term Debt $ 803,050 $ 774,857 (a) Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively. (b) Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 2016 and December 31, 2015, respectively. (c) 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, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5%
Principal Maturity Schedule for Total Debt Outstanding	The following is the principal maturity schedule for debt outstanding as of March 31, 2016: 2016 $ 9,906 2017 28 2018 — 2019 148,500 2020 652,658 Thereafter 15,865 Total (a) $ 826,957 (a) Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs

Derivative Instruments And Fa29

Derivative Instruments And Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2016 and 2015: For the Three Months Ended March 31, ($ in Thousands) 2016 2015 Oil $ 325 $ 2,876 Natural Gas 5,363 13,600 NGLs (1,621 ) 435 Refined Products (18 ) (55 ) Interest Rate — 263 Gain on Derivatives, Net $ 4,049 $ 17,119
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2016 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2016 - Collars 445,750 Bbls $ — $ 38.72 $ 50.28 $ — $ 662 2016 - Three-Way Collars 225,000 Bbls 31.20 41.40 49.60 — 340 2016 - Cap Swaps 60,000 Bbls 30.00 — — 44.00 42 730,750 Bbls $ 1,044 Natural Gas 2016 - Swaps 14,090,000 Mcf — — — 2.95 $ 10,341 2016 - Swaptions 900,000 Mcf — — — 3.15 767 2016 - Cap Swaps 4,050,000 Mcf 2.90 — — 3.48 1,102 2016 - Collars 2,250,000 Mcf — 2.70 3.10 — 973 2016 - Three-Way Collars 8,480,000 Mcf 2.31 2.95 3.55 — 5,054 2016 - Put Spreads 9,470,000 Mcf 2.50 3.26 — — 808 2016 - Basis Swaps - Dominion South 17,665,000 Mcf — — — (0.89 ) (1,879 ) 2017 - Swaps 960,000 Mcf — — — 3.60 903 2017 - Swaptions 0 Mcf — — — — (263 ) 2017 - Cap Swaps 5,700,000 Mcf 2.65 — — 3.20 951 2017 - Three-Way Collars 16,300,000 Mcf 2.33 3.02 3.89 — 5,066 2017 - Calls 3,000,000 Mcf — — 3.64 — (753 ) 2017 - Basis Swaps - Dominion South 4,550,000 Mcf — — — (0.83 ) (1,092 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (513 ) 2018 - Swaps 960,000 Mcf — — — 3.60 903 2018 - Swaptions 0 Mcf — — — — (191 ) 2018 - Cap Swaps 1,800,000 Mcf 3.30 — — 4.05 1,060 2018 - Three-Way Collars 7,875,000 Mcf 2.29 2.88 3.56 — 1,046 2018 - Calls 5,810,000 Mcf — — 3.97 — (328 ) 2018 - Basis Swaps - Dominion South 6,400,000 Mcf — — — (0.83 ) (1,092 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (513 ) 2019 - Basis Swaps - Dominion South 7,300,000 Mcf — — — (0.83 ) (1,092 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.83 ) (1,092 ) 154,080,000 Mcf $ 20,166 NGLs 2016 - C3+ NGL Swaps 1,038,000 Bbls — — — 30.66 $ 6,006 2016 - Ethane Swaps 165,000 Bbls — — — 8.82 155 2017 - C3+ NGL Swaps 468,000 Bbls — — — 20.16 (287 ) 1,671,000 Bbls $ 5,874 Refined Product (Heating Oil) 2016 - Swaps 9,000 Bbls $ — $ — $ — $ 84.00 $ (278 ) 9,000 Bbls $ (278 )
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, 2016 and December 31, 2015 is summarized below: March 31, December 31, ($ in Thousands) 2016 2015 Short-Term Derivative Assets: Crude Oil—Collars $ 662 $ 1,078 Crude Oil—Deferred Put Spread 42 852 Crude Oil—Three-Way Collars 616 577 NGL—Swaps 6,579 10,250 Natural Gas—Swaps 10,576 9,010 Natural Gas—Cap Swaps 1,638 1,977 Natural Gas—Basis Swaps — 70 Natural Gas—Three-Way Collars 6,326 6,183 Natural Gas—Collars 973 1,728 Natural Gas—Swaption 792 798 Natural Gas—Put Spread 808 1,737 Total Short-Term Derivative Assets $ 29,012 $ 34,260 Long-Term Derivative Assets: NGL—Swaps $ 185 $ 344 Natural Gas—Cap Swaps 1,855 2,294 Natural Gas—Swaps 1,580 1,593 Natural Gas—Basis Swaps — 195 Natural Gas—Three-Way Collars 4,840 5,108 Total Long-Term Derivative Assets $ 8,460 $ 9,534 Total Derivative Assets $ 37,472 $ 43,794 Short-Term Derivative Liabilities: Crude Oil—Three-Way Collars (276 ) — NGL—Swaps (490 ) — Refined Product—Swaps (278 ) (376 ) Natural Gas—Three-Way Collars — (31 ) Natural Gas—Basis Swaps (2,280 ) (1,585 ) Natural Gas—Call (189 ) — Natural Gas—Swaption (46 ) (202 ) Natural Gas—Swaps (9 ) (292 ) Natural Gas—Cap Swaps (190 ) — Total Short - Term Derivative Liabilities $ (3,758 ) $ (2,486 ) Long-Term Derivative Liabilities: NGL—Swaps (400 ) — Natural Gas—Swaption (433 ) (297 ) Natural Gas—Basis Swaps (4,993 ) (4,186 ) Natural Gas—Call (892 ) (989 ) Natural Gas—Cap Swaps (190 ) — Natural Gas—Three-Way Collars — (84 ) Total Long-Term Derivative Liabilities $ (6,908 ) $ (5,556 ) Total Derivative Liabilities $ (10,666 ) $ (8,042 )
Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps	The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of March 31, 2016 and December 31, 2015 are included in the table below. As of March 31, 2016 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.30) - ($1.02) $ (0.85 ) $ (6,247 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.09) - ($0.13) $ (0.13 ) $ (1,026 ) As of December 31, 2015 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.27) - ($1.08) $ (0.74 ) $ (5,468 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.05) - ($0.17) $ (0.12 ) $ (38 )
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value	The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at March 31, 2016 Using: ($ in Thousands) Total Carrying Value as of March 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 $ 26,806 $ — $ 34,079 $ (7,273 ) Fair Value Measurements at December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 )
Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3)	The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2016 and 2015: Three Months Ended March 31, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value (2,037 ) (1,955 ) Purchases — — Settlements Received 270 409 Ending Balance of Level 3 $ (7,273 ) $ (205 )
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, 2016 December 31, 2015 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 657,511 $ 78,715 $ 663,089 $ 137,402 Secured Line of Credit 152,794 152,794 109,396 109,396 Capital Leases and Other Obligations 434 427 618 606 Total $ 810,739 $ 231,936 $ 773,103 $ 247,404

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2016
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, ($ in Thousands) 2016 2015 Income (Expense) Benefit $ (2,092 ) $ 92 Effective Tax Rate -3.6 % 0.5 %

Employee Benefit And Equity P31

Employee Benefit And Equity Plans (Tables)	3 Months Ended
	Mar. 31, 2016
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, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 3/31/16 Weighted-Average Exercise Price Number Exercisable At 3/31/16 Weighted-Average Exercise Price $ 1.69 851,422 $ 1.69 — $ — $ 4.05 40,000 $ 4.05 — $ — $ 4.90 40,000 $ 4.90 3,333 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 11.87 3,500 $ 11.87 3,500 $ 11.87 $ 13.19 50,000 $ 13.19 50,000 $ 13.19 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,295,094 $ 4.41 367,005 $ 10.72
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, 2016 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 420,901 1.67 Forfeitures (346,876 ) 7.83 Vested (142,516 ) 12.76 Restricted stock awards, as of March 31, 2016 2,410,917 $ 4.86

Commitments and Contingencies (

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	As of March 31, 2016, 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, 2016 and 2015, was approximately $0.3 million and $0.2 million, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2016 $ 766 2017 991 2018 565 2019 563 2020 422 Thereafter — Total $ 3,307
Minimum Net Obligations under Sales, Gathering and Transportation Agreements	Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2016 $ 24,715 2017 49,357 2018 53,456 2019 52,904 2020 51,697 Thereafter 458,695 Total $ 690,824
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, 2016
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earning Per Common Share	The following table sets forth the computation of basic and diluted earnings per common share: (in thousands, except per share amounts) Three Months Ended March 31, Numerator: 2016 2015 Net Loss From Continuing Operations $ (60,141 ) $ (18,479 ) Net Income From Discontinued Operations, Less Noncontrolling Interests — 665 Less: Preferred Stock Dividends (2,105 ) (2,415 ) Net Loss Attributable to Common Shareholders $ (62,246 ) $ (20,229 ) Denominator: Weighted Average Common Shares Outstanding - Basic 56,003 54,370 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 56,003 54,370 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) — Net Income From Discontinued Operations — 0.01 — Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 ) Diluted — Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) — Net Income From Discontinued Operations — 0.01 — Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 )

Condensed Consolidating Finan34

Condensed Consolidating Financial Information (Tables)	3 Months Ended
	Mar. 31, 2016
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, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 24,888 $ — $ 3 $ — $ 24,891 Accounts Receivable 24,252 16 47 — 24,315 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 29,012 — — — 29,012 Inventory, Prepaid Expenses and Other 3,156 — 12 — 3,168 Total Current Assets 81,308 16 80 — 81,404 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,300,678 801 — 1,301,479 Unevaluated Oil and Gas Properties 257,697 — — — 257,697 Other Property and Equipment 40,133 895 — — 41,028 Wells and Facilities in Progress 75,269 245 — — 75,514 Pipelines 16,780 — — — 16,780 Total Property and Equipment 1,690,557 1,941 — — 1,692,498 Less: Accumulated Depreciation, Depletion and Amortization (720,100 ) (898 ) — — (720,998 ) Net Property and Equipment 970,457 1,043 — — 971,500 Other Assets 2,489 — — — 2,489 Intercompany Receivables — — 1,095,371 (1,095,371 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 8,460 — — — 8,460 Total Assets $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 42,818 $ — $ — $ — $ 42,818 Current Maturities of Long-Term Debt 434 — 9,500 — 9,934 Accrued Liabilities 32,709 20 11,567 44,296 Short-Term Derivative Instruments 3,758 — — — 3,758 Total Current Liabilities 79,719 20 21,067 — 100,806 Long-Term Derivative Instruments 6,908 — — — 6,908 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs — — 143,294 — 143,294 Senior Notes, Net of Issuance Costs — — 657,511 — 657,511 Premium on Senior Notes – Net — — 2,245 — 2,245 Other Deposits and Liabilities 3,140 — — — 3,140 Future Abandonment Cost 42,964 448 — — 43,412 Intercompany Payables 1,090,818 4,553 — (1,095,371 ) — Total Liabilities 1,223,549 5,021 824,117 (1,095,371 ) 957,316 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 63 — 63 Additional Paid-In Capital 177,144 — 630,301 (177,144 ) 630,301 Accumulated Earnings (Deficit) (340,367 ) (3,962 ) (487,005 ) 307,506 (523,828 ) Total Stockholders’ Equity (163,223 ) (3,962 ) 143,360 130,362 106,537 Total Liabilities and Stockholders’ Equity $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 19,423 11 49 — 19,483 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,804 — 25 — 3,829 Total Current Assets 58,576 11 94 — 58,681 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,245,626 774 — (6,970 ) 1,239,430 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 39,217 895 — — 40,112 Wells and Facilities in Progress 144,587 239 — (270 ) 144,556 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,708,583 1,908 — (9,377 ) 1,701,114 Less: Accumulated Depreciation, Depletion and Amortization (702,537 ) (880 ) — 3,518 (699,899 ) Net Property and Equipment 1,006,046 1,028 — (5,859 ) 1,001,215 Deferred Financing Costs and Other Assets—Net 2,501 — — — 2,501 Intercompany Receivables — — 1,070,548 (1,070,548 ) — Investment in Subsidiaries – Net (1,907 ) — 243,331 (241,424 ) — Long-Term Derivative Instruments 9,534 — — — 9,534 Total Assets $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 37,874 $ — $ — $ — $ 37,874 Current Maturities of Long-Term Debt 590 — — — 590 Accrued Liabilities 32,601 — 11,725 — 44,326 Short-Term Derivative Instruments 2,486 — — — 2,486 Total Current Liabilities 73,551 — 11,725 — 85,276 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 28 — 109,368 — 109,396 Senior Notes, Net of Issuance Costs — — 663,089 — 663,089 Premium on Senior Notes – Net — — 2,344 — 2,344 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 42,443 440 — — 42,883 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,830 892 786,526 (1,070,548 ) 911,700 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,143 — 619,777 (173,057 ) 623,863 Accumulated Earnings (Deficit) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931
Condensed Consolidating Statements of Operations	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 30,463 $ 31 $ — $ — $ 30,494 Other Revenue 13 — — — 13 TOTAL OPERATING REVENUE 30,476 31 — — 30,507 OPERATING EXPENSES Production and Lease Operating Expense 30,121 25 — — 30,146 General and Administrative Expense 6,068 9 (14 ) — 6,063 Gain on Disposal of Asset (30 ) — — — (30 ) Impairment Expense 14,184 — — — 14,184 Exploration Expense 993 — — — 993 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Other Operating Income 329 — — — 329 TOTAL OPERATING EXPENSES 71,044 63 (14 ) — 71,093 INCOME (LOSS) FROM OPERATIONS (40,568 ) (32 ) 14 — (40,586 ) OTHER INCOME (EXPENSE) Interest Expense (273 ) — (12,759 ) — (13,032 ) Gain on Derivatives, Net 4,049 — — — 4,049 Debt Exchange Expense — — (8,480 ) — (8,480 ) Income (Loss) From Equity in Consolidated Subsidiaries (25 ) 25 (38,151 ) 38,151 — TOTAL OTHER INCOME (EXPENSE) 3,751 25 (59,390 ) 38,151 (17,463 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (36,817 ) (7 ) (59,376 ) 38,151 (58,049 ) Income Tax Expense (1,326 ) (1 ) (765 ) — (2,092 ) NET INCOME (LOSS) (38,143 ) (8 ) (60,141 ) 38,151 (60,141 ) Preferred Stock Dividends — — 2,105 — 2,105 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (38,143 ) $ (8 ) $ (62,246 ) $ 38,151 $ (62,246 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 54,000 $ 111 $ — $ — $ 54,111 Other Revenue 11 — — — 11 TOTAL OPERATING REVENUE 54,011 111 — — 54,122 OPERATING EXPENSES Production and Lease Operating Expense 29,014 38 — — 29,052 General and Administrative Expense 6,659 16 2,976 — 9,651 Loss on Disposal of Asset 65 — — — 65 Impairment Expense 7,012 11 — — 7,023 Exploration Expense 518 — — — 518 Depreciation, Depletion, Amortization and Accretion 26,292 69 — (235 ) 26,126 Other Operating Expense 5,191 — — — 5,191 TOTAL OPERATING EXPENSES 74,751 134 2,976 (235 ) 77,626 INCOME (LOSS) FROM OPERATIONS (20,740 ) (23 ) (2,976 ) 235 (23,504 ) OTHER INCOME (EXPENSE) Interest Expense (58 ) — (11,959 ) — (12,017 ) Gain on Derivatives, Net 16,856 — 263 — 17,119 Other Expense 34 — — — 34 Loss From Equity Method Investments (203 ) — — — (203 ) Income (Loss) From Equity in Consolidated Subsidiaries (23 ) 23 (3,214 ) 3,214 — TOTAL OTHER INCOME (EXPENSE) 16,606 23 (14,910 ) 3,214 4,933 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (4,134 ) — (17,886 ) 3,449 (18,571 ) Income Tax Benefit 20 — 72 — 92 INCOME (LOSS) FROM CONTINUING OPERATIONS (4,114 ) — (17,814 ) 3,449 (18,479 ) Loss From Discontinued Operations, Net of Income Tax — 2,826 — (864 ) 1,962 Net Income (Loss) (4,114 ) 2,826 (17,814 ) 2,585 (16,517 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 1,297 — — 1,297 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (4,114 ) $ 1,529 $ (17,814 ) $ 2,585 $ (17,814 ) Preferred Stock Dividends — — 2,415 — 2,415 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (4,114 ) $ 1,529 $ (20,229 ) $ 2,585 $ (20,229 )
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (38,143 ) $ (8 ) $ (60,141 ) $ 38,151 $ (60,141 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (30 ) — 527 — 497 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Gain on Derivatives (4,049 ) — — — (4,049 ) Cash Settlements of Derivatives 12,994 — — — 12,994 Dry Hole Expense 843 — — — 843 Gain on Sale of Asset (30 ) — — — (30 ) Deferred Income Tax Expense 1,326 1 765 — 2,092 Impairment Expense 14,184 — 14,184 (14,184 ) 14,184 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 1,922 21 (2,251 ) — (308 ) Other Assets and Liabilities (170 ) — — — (170 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,726 53 (67,639 ) 23,967 (18,893 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27 (21 ) 23,961 (23,967 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 71 — — — 71 Proceeds from Joint Venture for Reimbursement of Capital Costs 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 (743 ) (53 ) 23,961 (23,967 ) (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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (4,114 ) $ 2,826 $ (17,814 ) $ 2,585 $ (16,517 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss From Equity Method Investments 203 — — — 203 Non-Cash Expenses (70 ) 44 3,403 — 3,377 Depreciation, Depletion, Amortization and Accretion 26,292 1,480 — (1,607 ) 26,165 Gain on Derivatives (16,856 ) — (263 ) — (17,119 ) Cash Settlements of Derivatives 10,579 — 500 — 11,079 Dry Hole Expense (1 ) — — — (1 ) (Gain) Loss on Sale of Asset 65 (32 ) — — 33 Impairment Expense 7,012 11 — — 7,023 Changes in operating assets and liabilities Accounts Receivable 10,437 (1,087 ) 428 251 10,029 Inventory, Prepaid Expenses and Other Assets 712 (322 ) (62 ) — 328 Accounts Payable and Accrued Liabilities (12,518 ) (2,496 ) 2,336 (251 ) (12,929 ) Other Assets and Liabilities (199 ) (133 ) 27 — (305 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 21,542 291 (11,445 ) 978 11,366 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27,192 (1,688 ) (23,681 ) (1,823 ) — Proceeds from Joint Venture Acreage Management 39 — — — 39 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 217 455 — — 672 Proceeds from Joint Venture for Reimbursement of Capital Costs 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (17,454 ) (5 ) — — (17,459 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (60,719 ) (7,139 ) — 845 (67,013 ) NET CASH USED IN INVESTING ACTIVITIES (34,114 ) (8,377 ) (23,681 ) (978 ) (67,150 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 18,826 54,000 — 72,826 Repayments of Long-Term Debt and Lines of Credit — (9,761 ) (16,000 ) — (25,761 ) Repayments of Loans and Other Notes Payable (392 ) (294 ) — — (686 ) Debt Issuance Costs — — (459 ) — (459 ) Dividends Paid — — (2,415 ) — (2,415 ) Distributions by the Partners of Consolidated Subsidiaries — (531 ) — — (531 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (392 ) 8,240 35,126 — 42,974 NET INCREASE IN CASH (12,964 ) 154 — — (12,810 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH - ENDING $ 5,014 $ 267 $ 5 $ — $ 5,286

Basis of Presentation and Pri35

Basis of Presentation and Principles of Consolidation - Additional Information (Details) - USD ($)		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior secured line of credit and long term debt, net issuance costs		$ 143,294,000	$ 109,396,000
Senior notes, net of issuance costs	[1]	$ 657,511,000	$ 663,089,000
8.875% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Interest rate		8.875%	8.875%
Debt instrument maturity date		Dec. 1, 2020
6.25% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Interest rate		6.25%	6.25%
Debt instrument maturity date		Aug. 1, 2022
Accounting Standards Update201503
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior secured line of credit and long term debt, net issuance costs			$ 2,100,000
Senior notes, net of issuance costs			11,900,000
Accounting Standards Update201503 | 8.875% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs			350,000,000
Accounting Standards Update201503 | 6.25% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs			325,000,000
Accounting Standards Update201517
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Long-term tax assets			12,500,000
Current deferred tax liability			12,500,000
Net deferred tax			$ 0
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Future Abandonment Cost - Addit

Future Abandonment Cost - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 856	$ 900

Future Abandonment Cost (Detail

Future Abandonment Cost (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance at January 1, 2016		$ 45,074
Future Abandonment Obligation Incurred		402
Future Abandonment Obligation Settled		(361)
Future Abandonment Obligation Cancelled or Sold		(189)
Future Abandonment Obligation Accretion Expense		856	$ 900
Total Future Abandonment Cost	[1]	$ 45,782
[1]	Includes approximately $2.4 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, 2016	Dec. 31, 2015
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 44,296	$ 44,326
Remediation Property for Sale, Abandonment or Disposal
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 2,400

Discontinued Operations_ Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Jul. 31, 2015	Mar. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain on asset held for sale	$ 66,800
Gain classified as other (income) expense		$ (34)
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership percentage by parent				60.00%
American Water Works Company, Inc.
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Aggregate consideration of Water Solutions			$ 130,000
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain classified as other (income) expense	$ 57,800	$ 103

Summary of Financial Informatio

Summary of Financial Information for Discontinued Operations (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Jul. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Revenues:
Total Operating Revenue		$ 30,507	$ 54,122
Costs and Expenses:
General and Administrative Expense		6,063	9,651
Depreciation, Depletion, Amortization and Accretion		19,408	26,126
Gain on Sale of Asset		(30)	65
Interest Expense		$ 13,032	12,017
Gain classified as other (income) expense			(34)
Income from Discontinued Operations, net of taxes			1,962
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Revenues:
Field Services Revenue			14,964
Total Operating Revenue			14,964
Costs and Expenses:
General and Administrative Expense			977
Depreciation, Depletion, Amortization and Accretion			39
Field Services Operating Expense			11,289
Gain on Sale of Asset			(32)
Interest Expense			191
Gain classified as other (income) expense	$ 57,800		103
Total Costs and Expenses			12,567
Income from Discontinued Operations Before Income Taxes			2,397
Income Tax Expense			(435)
Income from Discontinued Operations, net of taxes			$ 1,962

Business and Oil and Gas Prop41

Business and Oil and Gas Property Acquisitions and Dispositions - Additional Information (Details) $ in Thousands	Mar. 01, 2016USD ($)Well	Mar. 31, 2015USD ($)Well	Apr. 30, 2016Well	Mar. 31, 2016USD ($)Well	Mar. 31, 2015USD ($)
Business Acquisition And Dispositions [Line Items]
Payments for interest in wells that have been drilled or in process of being drilled | $				$ 15,068	$ 67,013
Arc Light Capital Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Percentage of estimated well costs		35.00%
Consideration for the transaction | $		$ 67,000
Amount received at closing of wells | $		$ 16,600
Payments for interest in wells that have been drilled or in process of being drilled | $				$ 52,200
Percentage of working interest attained through return on investment and internal rate of return		50.00%
Percentage of working interest		35.00%
Percentage of remaining working interest		17.50%
Number of drilled and completed wells to be placed into service				4
Arc Light Capital Partners Limited Liability Corporation | Butler County, Pennsylvania
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development		32
Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Consideration for the transaction | $	$ 175,000
Amount received at closing of wells | $	37,100
Payments for interest in wells that have been drilled or in process of being drilled | $	$ 19,500
Percentage of working interest	65.00%
Number of wells in which BSP Options to Participate in development				36
Number of producing wells				15
Number of drilled well that is awaiting completion				3
Number of wells awaiting pipeline connection				4
Benefit Street Partners Limited Liability Corporation | Minimum
Business Acquisition And Dispositions [Line Items]
Percentage of working interest earned in acreage	15.00%
Benefit Street Partners Limited Liability Corporation | Maximum
Business Acquisition And Dispositions [Line Items]
Percentage of working interest earned in acreage	20.00%
Benefit Street Partners Limited Liability Corporation | Subsequent Event
Business Acquisition And Dispositions [Line Items]
Number of wells to be drilled and completed in later period			4
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				12
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 | 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				3

Recently Issued Accounting Pr42

Recently Issued Accounting Pronouncements - Additional Information (Details) - USD ($)		Mar. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Senior secured line of credit and long term debt, net issuance costs		$ 143,294,000	$ 109,396,000
Senior notes, net of issuance costs	[1]	$ 657,511,000	663,089,000
Accounting Standards Update201503
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Senior secured line of credit and long term debt, net issuance costs			2,100,000
Senior notes, net of issuance costs			11,900,000
ASU 2015-17, Income Taxes
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Long-term deferred tax assets			12,500,000
Current deferred tax liability			12,500,000
Net deferred tax			$ 0
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Concentrations of Credit Risk -

Concentrations of Credit Risk - Additional Information (Details) - Sales - Customer Concentration Risk	3 Months Ended
	Mar. 31, 2016Customer
Purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	93.50%
Number of major customers	5
Largest single purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	46.00%

Long-Term Debt - Senior Credit

Long-Term Debt - Senior Credit Facility - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Apr. 01, 2016	Dec. 31, 2015	Mar. 31, 2015
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 158,000,000		$ 111,500,000
Cash and Cash Equivalents	24,891,000		$ 1,091,000	$ 4,964,000
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity	41,000,000
Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	200,000,000
Line of credit facility, maximum borrowing capacity	200,000,000
Line of credit facility, amount outstanding	158,000,000
Line of credit facility, remaining borrowing capacity	$ 1,000,000
Line of credit facility, maturity date	Sep. 12, 2019
Current ratio	0.06%
Senior Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Senior Credit Facility | Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	60,000,000
Line of credit facility, remaining borrowing capacity	41,000,000
Senior Credit Facility | Maximum
Debt Instrument [Line Items]
Cash and Cash Equivalents	$ 15,000,000
Criteria of net senior secured debt to EBITDAX	275.00%
Senior Credit Facility | Minimum
Debt Instrument [Line Items]
Criteria Current ratio	100.00%
Net senior secured debt to EBITDAX	210.00%
Senior Notes | Maximum
Debt Instrument [Line Items]
Criteria of net senior secured debt to EBITDAX	300.00%
Subsequent Event | Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 190,000,000

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Details) - USD ($) shares in Millions	Mar. 31, 2016	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
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	$ 6,477,000	6,477,000
Accrued and unpaid interest	12,800,000	12,800,000
Third-party debt issuance costs		$ 2,821,000	$ 459,000
Trailing quarters fixed charge coverage ratio				2.25%
Fixed charge coverage ratio		1.00%
Senior Notes additional borrowings	68,900,000	$ 68,900,000
Premium on Senior Notes, Net	2,245,000	2,245,000		$ 2,344,000
Amortization of net premium		100,000
Maximum
Debt Instrument [Line Items]
Senior notes offered for exchange		$ 675,000,000
Interest Payments One Through Three
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment		semi-annual
New Notes
Debt Instrument [Line Items]
Gain recognized due to troubled debt exchanges		$ 0
Aggregate principal amount	633,700,000	$ 633,700,000
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	$ 8,500,000
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%
New Notes | Interest Payments Four And Thereafter
Debt Instrument [Line Items]
Interest rate	8.00%
2020 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 324,000,000	$ 324,000,000
Percentage of senior notes exchanged for new notes	92.60%
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]
Debt instrument maturity date		Dec. 1, 2020
Interest rate	8.875%	8.875%		8.875%
6.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument maturity date		Aug. 1, 2022
Interest rate	6.25%	6.25%		6.25%

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Senior Notes, Net of Issuance Costs	[1]	$ 657,511	$ 663,089
Premium on Senior Notes, Net		2,245	2,344
Senior Line of Credit, Net of Issuance Costs	[2],[3]	152,794	109,396
Capital Leases and Other Obligations	[3]	434	618
Total Debt		812,984	775,447
Less Current Portion of Long-Term Debt		(9,934)	(590)
Total Long-Term Debt		$ 803,050	$ 774,857
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.
[2]	Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 2016 and December 31, 2015, respectively.
[3]	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, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively.

Components of Long-Term Debt 47

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Senior Notes
Debt Instrument [Line Items]
Unamortized debt issuance expense	$ 11.1	$ 11.9
Senior Line of Credit
Debt Instrument [Line Items]
Unamortized debt issuance expense	$ 5.2	$ 2.1
Senior Credit Facility
Debt Instrument [Line Items]
Average interest rate	3.20%	1.70%
Capital Leases and Other Obligations
Debt Instrument [Line Items]
Average interest rate	4.50%	5.50%

Principal Maturity Schedule for

Principal Maturity Schedule for Debt Outstanding (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Jan. 31, 2016		Dec. 31, 2015
Debt Disclosure [Abstract]
2,016		$ 9,906
2,017		28
2,019		148,500
2,020		652,658
Thereafter		15,865
Total	$ 810,739	$ 826,957	[1]	$ 773,103
[1]	Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs

Principal Maturity Schedule f49

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) $ in Millions	Mar. 31, 2016USD ($)
Debt Instrument [Line Items]
Senior notes, net premium	$ 2.2
New Notes
Debt Instrument [Line Items]
Debt issuance costs	$ 16.2

Derivative Instruments and Fa50

Derivative Instruments and Fair Value Measurements - Additional Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives	$ (12,994,000)	$ (11,079,000)
Senior Line of Credit	158,000,000		$ 111,500,000
Senior Notes	675,000,000
Derivative interest rate outstanding	0		0
Derivatives asset (liability)	26,800,000		35,800,000
Unrealized gain (loss) on commodity derivative contracts	2,000,000	(2,000,000)
Impairment Expense	14,184,000	7,023,000
Other Than Temporary Impairment
Derivatives Fair Value [Line Items]
Impairment Expense	14,200,000
Crude Oil
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 1,044,000
Crude Oil | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	100.00%
Natural Gas
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 20,166,000
Natural Gas | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	100.00%
Commodity hedged on annualized basis hedge through 2017	50.00%
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 5,874,000
Natural Gas Liquids | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	40.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives	$ 13,000,000	$ 10,600,000
Derivatives asset (liability)	$ 26,806,000		35,752,000
Interest Rate Swaption [Member]
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives			$ 500,000

Schedule of Location and Amount

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments Gain Loss [Line Items]
Gain on Derivatives, Net	$ 4,049	$ 17,119
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain on Derivatives, Net	325	2,876
Refined Products
Derivative Instruments Gain Loss [Line Items]
Gain on Derivatives, Net	(18)	(55)
Natural Gas
Derivative Instruments Gain Loss [Line Items]
Gain on Derivatives, Net	5,363	13,600
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain on Derivatives, Net	$ (1,621)	435
Interest Rate Swap
Derivative Instruments Gain Loss [Line Items]
Gain on Derivatives, Net		$ 263

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)$ / bbl$ / Mcf$ / galbblMcf	Dec. 31, 2015USD ($)
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 26,800	$ 35,800
2016 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	2,250,000
Floor | $ / bbl	2.70
Ceiling | $ / bbl	3.10
Derivatives asset (liability)	$ 973
2016 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	60,000
Put Option | $ / bbl	30
Swap | $ / bbl	44
Derivatives asset (liability)	$ 42
2018 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	0
Derivatives asset (liability)	$ (191)
Crude Oil
Derivatives Fair Value [Line Items]
Volume | bbl	730,750
Derivatives asset (liability)	$ 1,044
Crude Oil | 2016 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	445,750
Floor | $ / bbl	38.72
Ceiling | $ / bbl	50.28
Derivatives asset (liability)	$ 662
Crude Oil | 2016 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	225,000
Put Option | $ / bbl	31.20
Floor | $ / bbl	41.40
Ceiling | $ / bbl	49.60
Derivatives asset (liability)	$ 340
Refined Product (Heating Oil)
Derivatives Fair Value [Line Items]
Volume | bbl	9,000
Derivatives asset (liability)	$ (278)
Refined Product (Heating Oil) | 2016 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	9,000
Swap | $ / gal	84
Derivatives asset (liability)	$ (278)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	154,080,000
Derivatives asset (liability)	$ 20,166
Natural Gas | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	(6,247)	(5,468)
Natural Gas | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ (1,026)	$ (38)
Natural Gas | 2016 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	8,480,000
Put Option | $ / Mcf	2.31
Floor | $ / Mcf	2.95
Ceiling | $ / Mcf	3.55
Derivatives asset (liability)	$ 5,054
Natural Gas | 2016 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	4,050,000
Put Option | $ / Mcf	2.90
Swap | $ / Mcf	3.48
Derivatives asset (liability)	$ 1,102
Natural Gas | 2016 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	14,090,000
Swap | $ / Mcf	2.95
Derivatives asset (liability)	$ 10,341
Natural Gas | 2016 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	900,000
Swap | $ / Mcf	3.15
Derivatives asset (liability)	$ 767
Natural Gas | 2016 | Put Spreads
Derivatives Fair Value [Line Items]
Volume | Mcf	9,470,000
Put Option | $ / Mcf	2.50
Floor | $ / Mcf	3.26
Derivatives asset (liability)	$ 808
Natural Gas | 2016 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	17,665,000
Swap | $ / Mcf	(0.89)
Derivatives asset (liability)	$ (1,879)
Natural Gas | 2017 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	16,300,000
Put Option | $ / Mcf	2.33
Floor | $ / Mcf	3.02
Ceiling | $ / Mcf	3.89
Derivatives asset (liability)	$ 5,066
Natural Gas | 2017 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	5,700,000
Put Option | $ / Mcf	2.65
Swap | $ / Mcf	3.20
Derivatives asset (liability)	$ 951
Natural Gas | 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	960,000
Swap | $ / Mcf	3.60
Derivatives asset (liability)	$ 903
Natural Gas | 2017 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	0
Derivatives asset (liability)	$ (263)
Natural Gas | 2017 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	4,550,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,092)
Natural Gas | 2017 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	3,000,000
Ceiling | $ / Mcf	3.64
Derivatives asset (liability)	$ (753)
Natural Gas | 2017 | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ (513)
Natural Gas | 2018 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	7,875,000
Put Option | $ / Mcf	2.29
Floor | $ / Mcf	2.88
Ceiling | $ / Mcf	3.56
Derivatives asset (liability)	$ 1,046
Natural Gas | 2018 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	1,800,000
Put Option | $ / Mcf	3.30
Swap | $ / Mcf	4.05
Derivatives asset (liability)	$ 1,060
Natural Gas | 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	960,000
Swap | $ / Mcf	3.60
Derivatives asset (liability)	$ 903
Natural Gas | 2018 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	6,400,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,092)
Natural Gas | 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	5,810,000
Ceiling | $ / Mcf	3.97
Derivatives asset (liability)	$ (328)
Natural Gas | 2018 | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ (513)
Natural Gas | 2019 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,300,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,092)
Natural Gas | 2020 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,320,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,092)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	1,671,000
Derivatives asset (liability)	$ 5,874
Natural Gas Liquids | 2016 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,038,000
Swap | $ / bbl	30.66
Derivatives asset (liability)	$ 6,006
Natural Gas Liquids | 2016 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	165,000
Swap | $ / bbl	8.82
Derivatives asset (liability)	$ 155
Natural Gas Liquids | 2017 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	468,000
Swap | $ / bbl	20.16
Derivatives asset (liability)	$ (287)

Combined Fair Value of Derivati

Combined Fair Value of Derivatives (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$ 29,012	$ 34,260
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	8,460	9,534
Total Derivative Assets	37,472	43,794
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,758)	(2,486)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(6,908)	(5,556)
Total Derivative Liabilities	(10,666)	(8,042)
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	6,579	10,250
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	185	344
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(490)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(400)
Natural Gas
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(6,908)	(5,556)
Natural Gas | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	973	1,728
Natural Gas | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	6,326	6,183
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	4,840	5,108
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		(31)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(84)
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	10,576	9,010
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,580	1,593
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(9)	(292)
Natural Gas | Cap Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,638	1,977
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,855	2,294
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(190)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(190)
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		70
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		195
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(2,280)	(1,585)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(4,993)	(4,186)
Natural Gas | Swaptions
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	792	798
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(46)	(202)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(433)	(297)
Natural Gas | Put Spreads
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	808	1,737
Natural Gas | Calls
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(189)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(892)	(989)
Crude Oil | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	662	1,078
Crude Oil | Deferred Put Spreads
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	42	852
Crude Oil | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	616	577
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(276)
Refined Product (Heating Oil) | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	$ (278)	$ (376)

Significant Unobservable Inputs

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)$ / Mcf	Dec. 31, 2015USD ($)$ / Mcf
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability) | $	$ 26,800	$ 35,800
Natural Gas
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability) | $	$ 20,166
Natural Gas | Basis Swaps Dominion South
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.85)	(0.74)
Derivatives asset (liability) | $	$ (6,247)	$ (5,468)
Natural Gas | Basis Swaps Dominion South | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.30)	(0.27)
Natural Gas | Basis Swaps Dominion South | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(1.02)	(1.08)
Natural Gas | Basis Swaps Texas Gas
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.13)	(0.12)
Derivatives asset (liability) | $	$ (1,026)	$ (38)
Natural Gas | Basis Swaps Texas Gas | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.09)	(0.05)
Natural Gas | Basis Swaps Texas Gas | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.13)	(0.17)

Fair Value Hierarchy Table for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ 26,800	$ 35,800
Commodity derivatives
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	26,806	35,752
Commodity derivatives | Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	34,079	41,258
Commodity derivatives | Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (7,273)	$ (5,506)

Reconciliation of Commodity Der

Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3) (Details) - Commodity derivatives - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance of Level 3	$ (5,506)	$ 1,341
Changes in Fair Value	(2,037)	(1,955)
Settlements Received	270	409
Ending Balance of Level 3	$ (7,273)	$ (205)

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Jan. 31, 2016	[4]	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	[1]	$ 657,511			$ 663,089
Senior Line of Credit, Net of Issuance Costs	[2],[3]	152,794			109,396
Capital Leases and Other Obligations	[3]	434			618
Total		810,739	$ 826,957		773,103
Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs		78,715			137,402
Secured Line of Credit		152,794			109,396
Capital Leases and Other Obligations		427			606
Total		$ 231,936			$ 247,404
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.
[2]	Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 2016 and December 31, 2015, respectively.
[3]	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, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively.
[4]	Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs

Schedule of Income Tax Included

Schedule of Income Tax Included in Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Income Tax (Expense) Benefit	$ (2,092)	$ 92
Effective Tax Rate	(3.60%)	0.50%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Statutory rate	35.00%	35.00%
Cancellation of debt income	$ 543.2
Net operating loss carryforwards alternative minimum tax payment	$ 5.5
Income tax refunds		$ 0.5

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, 2016	Nov. 15, 2015	Aug. 15, 2015	May. 15, 2015	Feb. 15, 2015	Dec. 31, 2015
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized		100,000,000					100,000,000
Preferred Stock, shares authorized		100,000					100,000
Common Stock, shares issued		66,041,227					55,741,229
Common Stock, shares outstanding		66,041,227					55,741,229
Preferred Stock, par value		$ 1					$ 1
Preferred Stock, shares issued		12,836					16,100
Preferred Stock, shares outstanding		12,836					16,100
Preferred stock shares converted		10,100,000
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		12,836					16,100
Preferred Stock, shares outstanding		12,836					16,100
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		$ 150	$ 150	$ 150	$ 150
Accumulated dividends in arrears		$ 2.1
Quarterly cash dividend amount paid			$ 2.4	$ 2.4	$ 2.4	$ 2.4
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Liquidation preference per share		$ 10,000
Common Stock
Schedule Of Capitalization Equity [Line Items]
Preferred stock convertible preferred stock		1,800,000

Employee Benefit and Equity P61

Employee Benefit and Equity Plans - Additional Information (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2016USD ($)EmployeesPerson$ / sharesshares	Mar. 31, 2015USD ($)Personshares	Dec. 31, 2015$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of option issued to purchase common stock | shares	851,422	80,000
Stock options exercised | shares	0	0
Tax benefit	$ 0	$ 0
Outstanding weighted average remaining term (in years)	5 years 6 months
Weighted average remaining term of options exercisable (in years)	1 year 10 months 24 days
Aggregate intrinsic value of options outstanding	$ 0
Aggregate intrinsic value of options exercisable	0
Unrecognized compensation expense	500,000
Restricted Stock or Unit Expense	$ 1,500,000	$ 2,500,000
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of employees | Employees	29
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation expense	$ 3,600,000
Common stock issued by compensation committee | shares	420,901	1,336,295
Number of employees subjected to issuance of common stock | Person	22	126
Number of non employee contractor subject to issuance of common stock | Person		1
Fair value of TSR awards of per share estimated on date of grant | $ / shares	$ 1.67
Share-based compensation		$ 3,000,000
Unrecognized compensation expense weighted average period, in years	1 year 6 months
Vested stock | shares	142,516
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	235,573	189,872

Summary of Issued and Outstandi

Summary of Issued and Outstanding Stock Options (Details)	Mar. 31, 2016$ / sharesshares
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding | shares	1,295,094
Weighted-Average Exercise Price, Outstanding	$ 4.41
Number Exercisable | shares	367,005
Weighted-Average Exercise Price, Exercisable	$ 10.72
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	851,422
Weighted-Average Exercise Price, Outstanding	$ 1.69
Exercise Price Range 4.05
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.05
Number Outstanding | shares	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.05
Exercise Price Range 4.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.90
Number Outstanding | shares	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.90
Number Exercisable | shares	3,333
Weighted-Average Exercise Price, Exercisable	$ 4.90
Exercise Price Range 5.04
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 5.04
Number Outstanding | 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 11.87
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 11.87
Number Outstanding | shares	3,500
Weighted-Average Exercise Price, Outstanding	$ 11.87
Number Exercisable | shares	3,500
Weighted-Average Exercise Price, Exercisable	$ 11.87
Exercise Price Range 13.19
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 13.19
Number Outstanding | shares	50,000
Weighted-Average Exercise Price, Outstanding	$ 13.19
Number Exercisable | shares	50,000
Weighted-Average Exercise Price, Exercisable	$ 13.19
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)	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, 2016	Mar. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	2,479,408
Awards, Number of Shares	420,901	1,336,295
Forfeitures, Number of Shares	(346,876)
Vested, Number of Shares	(142,516)
Stock awards, ending balance, Number of Shares	2,410,917
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 6.27
Awards, Weighted Average Grant Date Fair Value	1.67
Forfeitures, Weighted Average Grant Date Fair Value	7.83
Vested, Weighted Average Grant Date Fair Value	12.76
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 4.86

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	1 Months Ended				3 Months Ended
	Jan. 31, 2016USD ($)	Jan. 31, 2015USD ($)	Jul. 31, 2012Lawsuit	Oct. 31, 2011Person	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)Rigs	Dec. 31, 2015USD ($)	Sep. 30, 2015Rigs
Loss Contingencies [Line Items]
Significant probable or possible environmental contingent liabilities					$ 0
Letters of credit					41,000,000
Rent expense					300,000	$ 200,000
Termination fees incurred						4,800,000
Loss on Contract Termination	$ 2,500,000	$ 2,500,000
Maximum guarantee of payment of obligations					$ 418,000,000
Guarantee obligations period					2,021
Transportation, processing and marketing expenses of oil natural gas and natural gas liquids					$ 21,500,000	18,900,000
Fees related to unutilized capacity commitments					400,000	900,000
Production and Lease Operating Expense					30,146,000	29,052,000
Accrued Liabilities					$ 44,296,000		$ 44,326,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest					53.00%
Charges incurred for unutilized processing capacity					$ 600,000	$ 200,000
Capacity Reservation | 2016
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed					10,900,000
Capacity Reservation | 2017
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed					16,500,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed					16,500,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed					16,500,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed					16,600,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed					97,900,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations | Rigs								1
Number of contracts terminated | Rigs						2
Drilling Commitments | 2016
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs					1,700,000
Minimum gross cost to retain the completion services					4,000,000
Drilling Commitments | 2017
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs					2,300,000
Drilling Commitments | 2018
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs					$ 300,000
Pennsylvania Impact Fee
Loss Contingencies [Line Items]
Rate in which unconventional wells are charged					20.00%
Production and Lease Operating Expense					$ 500,000	$ 600,000
Accrued Liabilities					$ 3,600,000
the Cardinale case
Loss Contingencies [Line Items]
Number of plaintiffs | Person				2
Number of additional lawsuits filed | Lawsuit			2

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Details) $ in Thousands	Mar. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 766
2,017	991
2,018	565
2,019	563
2,020	422
Total	$ 3,307

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands	Mar. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 24,715
2,017	49,357
2,018	53,456
2,019	52,904
2,020	51,697
Thereafter	458,695
Total	$ 690,824

Fee for Unconventional Gas Well

Fee for Unconventional Gas Wells (Details) - Pennsylvania Impact Fee	3 Months Ended
	Mar. 31, 2016USD ($)	[1]
Less than $2.25
Unconventional Gas Wells [Line Items]
Year One	$ 40,200
Year Two	30,200
Year Three	25,200
Year 4 – 10	10,100
Year 11 – 15	5,000
$2.26 - $2.99
Unconventional Gas Wells [Line Items]
Year One	45,300
Year Two	35,200
Year Three	30,200
Year 4 – 10	15,100
Year 11 – 15	5,000
$3.00 - $4.99
Unconventional Gas Wells [Line Items]
Year One	50,300
Year Two	40,200
Year Three	30,200
Year 4 – 10	20,100
Year 11 – 15	10,100
$5.00 - $5.99
Unconventional Gas Wells [Line Items]
Year One	55,300
Year Two	45,300
Year Three	40,200
Year 4 – 10	20,100
Year 11 – 15	10,100
More than $5.99
Unconventional Gas Wells [Line Items]
Year One	60,400
Year Two	55,300
Year Three	50,300
Year 4 – 10	20,100
Year 11 – 15	$ 10,100
[1]	Pricing utilized for determining annual 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, 2016	Mar. 31, 2015
6.0% convertible perpetual preferred stock, Series A
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Dividend per share percentage	6.00%
Conversion of Preferred Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	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	1.3	0.5
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	0.7	1.3

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, 2016	Mar. 31, 2015
Numerator:
Net Loss From Continuing Operations	$ (60,141)	$ (18,479)
Net Income From Discontinued Operations, Less Noncontrolling Interests		665
Less: Preferred Stock Dividends	(2,105)	(2,415)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (62,246)	$ (20,229)
Denominator:
Weighted Average Common Shares Outstanding - Basic	56,003	54,370
Effect of Dilutive Securities:
Weighted Average Common Shares Outstanding - Diluted	56,003	54,370
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Loss From Continuing Operations	$ (1.11)	$ (0.38)
Basic — Net Income From Discontinued Operations		0.01
Basic – Net Loss Attributable to Rex Energy Common Shareholders	(1.11)	(0.37)
Diluted — Net Loss From Continuing Operations	(1.11)	(0.38)
Diluted — Net Income From Discontinued Operations		0.01
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (0.37)

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015
Schedule Of Equity Method Investments [Line Items]
Impairment Expense	$ 14,184,000		$ 7,023,000
Loss on Equity Method Investments			(203,000)
Equity Method Investments		$ 0
Production and Lease Operating Expense	$ 30,146,000		29,052,000
RW Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%
Impairment Expense		$ 17,500,000
Contributions to Equity Method Investments	$ 0		0
Loss on Equity Method Investments	(500,000)		(500,000)
Impairment charge in percentage		100.00%
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, 2016	Mar. 31, 2015
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$ 14,184	$ 7,023
Illinois Basin | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	3,500
Appalachian Basin
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense		3,000
Undeveloped properties, cost	257,700
Appalachian Basin | Unproved Property Impairments
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$ 10,700
Clearfield Country, Pennsylvania | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense		$ 4,000

Exploration Expense - Additiona

Exploration Expense - Additional Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)Well	Mar. 31, 2015USD ($)
Exploration Expense [Line Items]
Exploration Expense	$ 993	$ 518
Geological and Geophysical Type Expenditures
Exploration Expense [Line Items]
Exploration Expense	200
Dry Hole Expense For Non Operated Properties | Appalachian Basin
Exploration Expense [Line Items]
Exploration Expense	$ 800
Number of exploratory wells | Well	2

Condensed Consolidating Finan74

Condensed Consolidating Financial Information - Additional Information (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Net of Issuance Costs	[1]	$ 657,511	$ 663,089
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Details) - USD ($)		Mar. 31, 2016	Dec. 31, 2015	Jun. 30, 2015	Mar. 31, 2015
Current Assets
Cash and Cash Equivalents		$ 24,891,000	$ 1,091,000		$ 4,964,000
Accounts Receivable		24,315,000	19,483,000
Taxes Receivable		18,000	18,000
Short-Term Derivative Instruments		29,012,000	34,260,000
Inventory, Prepaid Expenses and Other		3,168,000	3,829,000
Total Current Assets		81,404,000	58,681,000
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,301,479,000	1,239,430,000
Unevaluated Oil and Gas Properties		257,697,000	262,992,000
Other Property and Equipment		41,028,000	40,112,000
Wells and Facilities in Progress		75,514,000	144,556,000
Pipelines		16,780,000	14,024,000
Total Property and Equipment		1,692,498,000	1,701,114,000
Less: Accumulated Depreciation, Depletion and Amortization		(720,998,000)	(699,899,000)
Net Property and Equipment		971,500,000	1,001,215,000
Deferred Financing Costs and Other Assets—Net			2,501,000
Equity Method Investments				$ 0
Other Assets		2,489,000	2,501,000
Long-Term Derivative Instruments		8,460,000	9,534,000
Total Assets		1,063,853,000	1,071,931,000
Current Liabilities
Accounts Payable		42,818,000	37,874,000
Current Maturities of Long-Term Debt		9,934,000	590,000
Accrued Liabilities		44,296,000	44,326,000
Short-Term Derivative Instruments		3,758,000	2,486,000
Total Current Liabilities		100,806,000	85,276,000
Long-Term Derivative Instruments		6,908,000	5,556,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		143,294,000	109,396,000
Senior Notes, Net of Issuance Costs	[1]	657,511,000	663,089,000
Premium on Senior Notes, Net		2,245,000	2,344,000
Other Deposits and Liabilities		3,140,000	3,156,000
Future Abandonment Cost		43,412,000	42,883,000
Total Liabilities		957,316,000	911,700,000
Stockholders’ Equity
Preferred Stock		1,000	1,000
Common Stock		63,000	54,000
Additional Paid-In Capital		630,301,000	623,863,000
Accumulated Earnings (Deficit)		(523,828,000)	(463,687,000)
Total Stockholders’ Equity		106,537,000	160,231,000
Total Liabilities and Stockholders’ Equity		1,063,853,000	1,071,931,000
Eliminations
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			(6,970,000)
Wells and Facilities in Progress			(270,000)
Pipelines			(2,137,000)
Total Property and Equipment			(9,377,000)
Less: Accumulated Depreciation, Depletion and Amortization			3,518,000
Net Property and Equipment			(5,859,000)
Intercompany Receivables		(1,095,371,000)	(1,070,548,000)
Investment in Subsidiaries – Net		130,362,000	(241,424,000)
Total Assets		(965,009,000)	(1,317,831,000)
Current Liabilities
Intercompany Payables		(1,095,371,000)	(1,070,548,000)
Total Liabilities		(1,095,371,000)	(1,070,548,000)
Stockholders’ Equity
Additional Paid-In Capital		(177,144,000)	(173,057,000)
Accumulated Earnings (Deficit)		307,506,000	(74,226,000)
Total Stockholders’ Equity		130,362,000	(247,283,000)
Total Liabilities and Stockholders’ Equity		(965,009,000)	(1,317,831,000)
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents		24,888,000	1,089,000
Accounts Receivable		24,252,000	19,423,000
Short-Term Derivative Instruments		29,012,000	34,260,000
Inventory, Prepaid Expenses and Other		3,156,000	3,804,000
Total Current Assets		81,308,000	58,576,000
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,300,678,000	1,245,626,000
Unevaluated Oil and Gas Properties		257,697,000	262,992,000
Other Property and Equipment		40,133,000	39,217,000
Wells and Facilities in Progress		75,269,000	144,587,000
Pipelines		16,780,000	16,161,000
Total Property and Equipment		1,690,557,000	1,708,583,000
Less: Accumulated Depreciation, Depletion and Amortization		(720,100,000)	(702,537,000)
Net Property and Equipment		970,457,000	1,006,046,000
Deferred Financing Costs and Other Assets—Net			2,501,000
Other Assets		2,489,000
Investment in Subsidiaries – Net		(2,388,000)	(1,907,000)
Long-Term Derivative Instruments		8,460,000	9,534,000
Total Assets		1,060,326,000	1,074,750,000
Current Liabilities
Accounts Payable		42,818,000	37,874,000
Current Maturities of Long-Term Debt		434,000	590,000
Accrued Liabilities		32,709,000	32,601,000
Short-Term Derivative Instruments		3,758,000	2,486,000
Total Current Liabilities		79,719,000	73,551,000
Long-Term Derivative Instruments		6,908,000	5,556,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs			28,000
Other Deposits and Liabilities		3,140,000	3,156,000
Future Abandonment Cost		42,964,000	42,443,000
Intercompany Payables		1,090,818,000	1,070,096,000
Total Liabilities		1,223,549,000	1,194,830,000
Stockholders’ Equity
Additional Paid-In Capital		177,144,000	177,143,000
Accumulated Earnings (Deficit)		(340,367,000)	(297,223,000)
Total Stockholders’ Equity		(163,223,000)	(120,080,000)
Total Liabilities and Stockholders’ Equity		1,060,326,000	1,074,750,000
Non-Guarantor Subsidiaries
Current Assets
Accounts Receivable		16,000	11,000
Total Current Assets		16,000	11,000
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		801,000	774,000
Other Property and Equipment		895,000	895,000
Wells and Facilities in Progress		245,000	239,000
Total Property and Equipment		1,941,000	1,908,000
Less: Accumulated Depreciation, Depletion and Amortization		(898,000)	(880,000)
Net Property and Equipment		1,043,000	1,028,000
Total Assets		1,059,000	1,039,000
Current Liabilities
Accrued Liabilities		20,000
Total Current Liabilities		20,000
Future Abandonment Cost		448,000	440,000
Intercompany Payables		4,553,000	452,000
Total Liabilities		5,021,000	892,000
Stockholders’ Equity
Accumulated Earnings (Deficit)		(3,962,000)	147,000
Total Stockholders’ Equity		(3,962,000)	147,000
Total Liabilities and Stockholders’ Equity		1,059,000	1,039,000
Parent Company
Current Assets
Cash and Cash Equivalents		3,000	2,000
Accounts Receivable		47,000	49,000
Taxes Receivable		18,000	18,000
Inventory, Prepaid Expenses and Other		12,000	25,000
Total Current Assets		80,000	94,000
Property and Equipment (Successful Efforts Method)
Intercompany Receivables		1,095,371,000	1,070,548,000
Investment in Subsidiaries – Net		(127,974,000)	243,331,000
Total Assets		967,477,000	1,313,973,000
Current Liabilities
Current Maturities of Long-Term Debt		9,500,000
Accrued Liabilities		11,567,000	11,725,000
Total Current Liabilities		21,067,000	11,725,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		143,294,000	109,368,000
Senior Notes, Net of Issuance Costs		657,511,000	663,089,000
Premium on Senior Notes, Net		2,245,000	2,344,000
Total Liabilities		824,117,000	786,526,000
Stockholders’ Equity
Preferred Stock		1,000	1,000
Common Stock		63,000	54,000
Additional Paid-In Capital		630,301,000	619,777,000
Accumulated Earnings (Deficit)		(487,005,000)	(92,385,000)
Total Stockholders’ Equity		143,360,000	527,447,000
Total Liabilities and Stockholders’ Equity		$ 967,477,000	$ 1,313,973,000
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$ 30,494	$ 54,111
Other Revenue	13	11
TOTAL OPERATING REVENUE	30,507	54,122
OPERATING EXPENSES
Production and Lease Operating Expense	30,146	29,052
General and Administrative Expense	6,063	9,651
(Gain) Loss on Disposal of Asset	(30)	65
Impairment Expense	14,184	7,023
Exploration Expense	993	518
Depreciation, Depletion, Amortization and Accretion	19,408	26,126
Other Operating Expense	329	5,191
TOTAL OPERATING EXPENSES	71,093	77,626
LOSS FROM OPERATIONS	(40,586)	(23,504)
OTHER INCOME (EXPENSE)
Interest Expense	(13,032)	(12,017)
Gain on Derivatives, Net	4,049	17,119
Other Income (Expense)		34
Debt Exchange Expense	(8,480)
Loss on Equity Method Investments		(203)
TOTAL OTHER INCOME (EXPENSE)	(17,463)	4,933
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(58,049)	(18,571)
Income Tax (Expense) Benefit	(2,092)	92
NET LOSS FROM CONTINUING OPERATIONS	(60,141)	(18,479)
Income (Loss) From Discontinued Operations, Net of Income Tax		1,962
NET LOSS	(60,141)	(16,517)
Net Income (Loss) Attributable to Noncontrolling Interests of Discontinued Operations		1,297
NET LOSS ATTRIBUTABLE TO REX ENERGY	(60,141)	(17,814)
Preferred Stock Dividends	2,105	2,415
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(62,246)	(20,229)
Eliminations
OPERATING EXPENSES
Depreciation, Depletion, Amortization and Accretion		(235)
TOTAL OPERATING EXPENSES		(235)
LOSS FROM OPERATIONS		235
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries	38,151	3,214
TOTAL OTHER INCOME (EXPENSE)	38,151	3,214
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	38,151	3,449
NET LOSS FROM CONTINUING OPERATIONS		3,449
Income (Loss) From Discontinued Operations, Net of Income Tax		(864)
NET LOSS	38,151	2,585
NET LOSS ATTRIBUTABLE TO REX ENERGY		2,585
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	38,151	2,585
Guarantor Subsidiaries
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	30,463	54,000
Other Revenue	13	11
TOTAL OPERATING REVENUE	30,476	54,011
OPERATING EXPENSES
Production and Lease Operating Expense	30,121	29,014
General and Administrative Expense	6,068	6,659
(Gain) Loss on Disposal of Asset	(30)	65
Impairment Expense	14,184	7,012
Exploration Expense	993	518
Depreciation, Depletion, Amortization and Accretion	19,379	26,292
Other Operating Expense	329	5,191
TOTAL OPERATING EXPENSES	71,044	74,751
LOSS FROM OPERATIONS	(40,568)	(20,740)
OTHER INCOME (EXPENSE)
Interest Expense	(273)	(58)
Gain on Derivatives, Net	4,049	16,856
Other Income (Expense)		34
Loss on Equity Method Investments		(203)
Income (Loss) From Equity in Consolidated Subsidiaries	(25)	(23)
TOTAL OTHER INCOME (EXPENSE)	3,751	16,606
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(36,817)	(4,134)
Income Tax (Expense) Benefit	(1,326)	20
NET LOSS FROM CONTINUING OPERATIONS		(4,114)
NET LOSS	(38,143)	(4,114)
NET LOSS ATTRIBUTABLE TO REX ENERGY		(4,114)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(38,143)	(4,114)
Non-Guarantor Subsidiaries
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	31	111
TOTAL OPERATING REVENUE	31	111
OPERATING EXPENSES
Production and Lease Operating Expense	25	38
General and Administrative Expense	9	16
Impairment Expense		11
Depreciation, Depletion, Amortization and Accretion	29	69
TOTAL OPERATING EXPENSES	63	134
LOSS FROM OPERATIONS	(32)	(23)
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries	25	23
TOTAL OTHER INCOME (EXPENSE)	25	23
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(7)
Income Tax (Expense) Benefit	(1)
Income (Loss) From Discontinued Operations, Net of Income Tax		2,826
NET LOSS	(8)	2,826
Net Income (Loss) Attributable to Noncontrolling Interests of Discontinued Operations		1,297
NET LOSS ATTRIBUTABLE TO REX ENERGY		1,529
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(8)	1,529
Parent Company
OPERATING EXPENSES
General and Administrative Expense	(14)	2,976
TOTAL OPERATING EXPENSES	(14)	2,976
LOSS FROM OPERATIONS	14	(2,976)
OTHER INCOME (EXPENSE)
Interest Expense	(12,759)	(11,959)
Gain on Derivatives, Net		263
Debt Exchange Expense	(8,480)
Income (Loss) From Equity in Consolidated Subsidiaries	(38,151)	(3,214)
TOTAL OTHER INCOME (EXPENSE)	(59,390)	(14,910)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(59,376)	(17,886)
Income Tax (Expense) Benefit	(765)	72
NET LOSS FROM CONTINUING OPERATIONS		(17,814)
NET LOSS	(60,141)	(17,814)
NET LOSS ATTRIBUTABLE TO REX ENERGY		(17,814)
Preferred Stock Dividends	2,105	2,415
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (62,246)	$ (20,229)

Condensed Consolidating State77

Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (60,141)	$ (16,517)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		203
Non-Cash Expenses (Income)	497	3,377
Depreciation, Depletion, Amortization and Accretion	19,408	26,165
Gain on Derivatives	(4,049)	(17,119)
Cash Settlements of Derivatives	12,994	11,079
Dry Hole Expense	843	(1)
(Gain) Loss on Sale of Asset	(30)	33
Deferred Income Tax Expense	2,092
Impairment Expense	14,184	7,023
Changes in operating assets and liabilities
Accounts Receivable	(4,873)	10,029
Inventory, Prepaid Expenses and Other Assets	660	328
Accounts Payable and Accrued Liabilities	(308)	(12,929)
Other Assets and Liabilities	(170)	(305)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(18,893)	11,366
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		39
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	71	672
Proceeds from Joint Venture for Reimbursement of Capital Costs	19,461	16,611
Acquisitions of Undeveloped Acreage	(5,266)	(17,459)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(15,068)	(67,013)
NET CASH USED IN INVESTING ACTIVITIES	(802)	(67,150)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit	46,500	72,826
Repayments of Long-Term Debt and Lines of Credit		(25,761)
Repayments of Loans and Other Notes Payable	(184)	(686)
Debt Issuance Costs	(2,821)	(459)
Dividends Paid		(2,415)
Distributions by the Partners of Consolidated Joint Ventures		(531)
NET CASH PROVIDED BY FINANCING ACTIVITIES	43,495	42,974
NET INCREASE (DECREASE) IN CASH	23,800	(12,810)
CASH – BEGINNING	1,091	18,096	$ 18,096
CASH – ENDING	24,891	5,286	1,091
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	38,151	2,585
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion		(1,607)
Impairment Expense	(14,184)
Changes in operating assets and liabilities
Accounts Receivable		251
Accounts Payable and Accrued Liabilities		(251)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	23,967	978
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries	(23,967)	(1,823)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		845
NET CASH USED IN INVESTING ACTIVITIES	(23,967)	(978)
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	(38,143)	(4,114)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		203
Non-Cash Expenses (Income)	(30)	(70)
Depreciation, Depletion, Amortization and Accretion	19,379	26,292
Gain on Derivatives	(4,049)	(16,856)
Cash Settlements of Derivatives	12,994	10,579
Dry Hole Expense	843	(1)
(Gain) Loss on Sale of Asset	(30)	65
Deferred Income Tax Expense	1,326
Impairment Expense	14,184	7,012
Changes in operating assets and liabilities
Accounts Receivable	15,852	10,437
Inventory, Prepaid Expenses and Other Assets	648	712
Accounts Payable and Accrued Liabilities	1,922	(12,518)
Other Assets and Liabilities	(170)	(199)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	24,726	21,542
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries	27	27,192
Proceeds from Joint Venture Acreage Management		39
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	71	217
Proceeds from Joint Venture for Reimbursement of Capital Costs	19,461	16,611
Acquisitions of Undeveloped Acreage	(5,266)	(17,454)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(15,036)	(60,719)
NET CASH USED IN INVESTING ACTIVITIES	(743)	(34,114)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable	(184)	(392)
NET CASH PROVIDED BY FINANCING ACTIVITIES	(184)	(392)
NET INCREASE (DECREASE) IN CASH	23,799	(12,964)
CASH – BEGINNING	1,089	17,978	17,978
CASH – ENDING	24,888	5,014	1,089
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	(8)	2,826
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)		44
Depreciation, Depletion, Amortization and Accretion	29	1,480
(Gain) Loss on Sale of Asset		(32)
Deferred Income Tax Expense	1
Impairment Expense		11
Changes in operating assets and liabilities
Accounts Receivable	10	(1,087)
Inventory, Prepaid Expenses and Other Assets		(322)
Accounts Payable and Accrued Liabilities	21	(2,496)
Other Assets and Liabilities		(133)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	53	291
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries	(21)	(1,688)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		455
Acquisitions of Undeveloped Acreage		(5)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(32)	(7,139)
NET CASH USED IN INVESTING ACTIVITIES	(53)	(8,377)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		18,826
Repayments of Long-Term Debt and Lines of Credit		(9,761)
Repayments of Loans and Other Notes Payable		(294)
Distributions by the Partners of Consolidated Joint Ventures		(531)
NET CASH PROVIDED BY FINANCING ACTIVITIES		8,240
NET INCREASE (DECREASE) IN CASH		154
CASH – BEGINNING		113	113
CASH – ENDING		267
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	(60,141)	(17,814)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)	527	3,403
Gain on Derivatives		(263)
Cash Settlements of Derivatives		500
Deferred Income Tax Expense	765
Impairment Expense	14,184
Changes in operating assets and liabilities
Accounts Receivable	(20,735)	428
Inventory, Prepaid Expenses and Other Assets	12	(62)
Accounts Payable and Accrued Liabilities	(2,251)	2,336
Other Assets and Liabilities		27
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(67,639)	(11,445)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries	23,961	(23,681)
NET CASH USED IN INVESTING ACTIVITIES	23,961	(23,681)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit	46,500	54,000
Repayments of Long-Term Debt and Lines of Credit		(16,000)
Debt Issuance Costs	(2,821)	(459)
Dividends Paid		(2,415)
NET CASH PROVIDED BY FINANCING ACTIVITIES	43,679	35,126
NET INCREASE (DECREASE) IN CASH	1
CASH – BEGINNING	2	5	5
CASH – ENDING	$ 3	$ 5	$ 2

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) shares in Millions	Apr. 30, 2016USD ($)Exchangeshares	Apr. 01, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Subsequent Event [Line Items]
Line of credit facility, amount outstanding			$ 158,000,000	$ 111,500,000
Letter Of Credit
Subsequent Event [Line Items]
Line of credit facility, remaining borrowing capacity			41,000,000
Senior Credit Facility
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity			200,000,000
Line of credit facility, amount outstanding			158,000,000
Line of credit facility, remaining borrowing capacity			1,000,000
Senior Credit Facility | Letter Of Credit
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity			60,000,000
Line of credit facility, remaining borrowing capacity			$ 41,000,000
Subsequent Event
Subsequent Event [Line Items]
Number of privately negotiated exchange for shares | Exchange	2
Debt converted to common stock | shares	7.1
Subsequent Event | Senior Credit Facility
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity		$ 190,000,000
Payment of down borrowings under Senior Credit Facility		$ 9,500,000
Subsequent Event | 6.0% convertible perpetual preferred stock, Series A
Subsequent Event [Line Items]
Preferred shares, amount	$ 13,800,000
Subsequent Event | 2020 Notes
Subsequent Event [Line Items]
Debt amount for conversion	17,200,000
Subsequent Event | 2022 Notes
Subsequent Event [Line Items]
Debt amount for conversion	9,700,000
Subsequent Event | New Notes
Subsequent Event [Line Items]
Debt amount for conversion	$ 2,200,000