Form 10-Q EV Energy Partners, LP For: Mar 31

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION  

Washington, D.C. 20549 

 

Form 10-Q 

 

þ

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2016 

OR 

 

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number 

001-33024  

 

EV Energy Partners, L.P. 

(Exact name of registrant as specified in its charter) 

 

Delaware (State or other jurisdiction of incorporation or organization)		20–4745690 (I.R.S. Employer Identification No.)
1001 Fannin, Suite 800, Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

 

Registrant’s telephone number, including area code: (713) 651-1144 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

YES þ NO ¨

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES þ NO ¨

 

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange Act. Check one: 

Large accelerated filer þ		Accelerated filer ¨		Non-accelerated filer ¨		Smaller reporting company ¨

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).  

YES ¨ NO þ 

 

As of April 29, 2016, the registrant had 49,055,214 common units outstanding.

 

 

 

Table of Contents   

 

PART I. FINANCIAL INFORMATION			2
Item 1.	Condensed Consolidated Financial Statements (Unaudited)		2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		24
Item 4.	Controls and Procedures		25
PART II. OTHER INFORMATION			25
Item 1.	Legal Proceedings		25
Item 1A.	Risk Factors		25
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		25
Item 3.	Defaults Upon Senior Securities		25
Item 4.	Mine Safety Disclosures		26
Item 5.	Other Information		26
Item 6.	Exhibits		26
Signatures			27

 

 

PART I. FINANCIAL INFORMATION 

 

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

EV Energy Partners, L.P. 

Condensed Consolidated Balance Sheets 

(In thousands, except number of units) 

(Unaudited) 

 

		March 31,				December 31,
		2016				2015
ASSETS
Current assets:
Cash and cash equivalents		$	3,868			$	20,415
Accounts receivable:
Oil, natural gas and natural gas liquids revenues			18,226				24,285
Other			2,084				7,137
Derivative asset			55,136				60,662
Other current assets			3,112				3,057
Total current assets			82,426				115,556
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; March 31, 2016, $999,704; December 31, 2015, $971,499			1,766,188				1,790,455
Other property, net of accumulated depreciation and amortization; March 31, 2016, $978; December 31, 2015, $970			1,029				1,019
Long–term derivative asset			8,096				10,741
Other assets			5,644				5,831
Total assets		$	1,863,383			$	1,923,602
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Third party		$	45,118			$	43,135
Related party			6,526				5,952
Income taxes			339				11,657
Total current liabilities			51,983				60,744
Asset retirement obligations			174,974				174,003
Long–term debt			665,792				688,614
Long–term derivative liability			1,820				-
Other long–term liabilities			1,523				1,682
Commitments and contingencies
Owners’ equity:
Common unitholders – 49,055,214 units and 48,871,399 units issued and outstanding as of March 31, 2016 and December 31, 2015, respectively			980,864				1,011,509
General partner interest			(13,573	)			(12,950	)
Total owners’ equity			967,291				998,559
Total liabilities and owners’ equity		$	1,863,383			$	1,923,602

  

See accompanying notes to unaudited condensed consolidated financial statements.

 

 

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Operations 

(In thousands, except per unit data) 

(Unaudited) 

 

		Three Months Ended
		March 31,
		2016				2015
Revenues:
Oil, natural gas and natural gas liquids revenues		$	37,739			$	46,425
Transportation and marketing–related revenues			511				817
Total revenues			38,250				47,242
Operating costs and expenses:
Lease operating expenses			28,915				23,524
Cost of purchased natural gas			336				574
Dry hole and exploration costs			130				414
Production taxes			1,671				1,748
Accretion expense on obligations			2,040				1,201
Depreciation, depletion and amortization			28,205				25,896
General and administrative expenses			8,378				12,415
Impairment of oil and natural gas properties			687				58,173
Gain on settlement of contract			(3,185	)			-
Gain on sales of oil and natural gas properties			-				(537	)
Total operating costs and expenses			67,177				123,408
Operating loss			(28,927	)			(76,166	)
Other (expense) income, net:
Gain on derivatives, net			9,834				23,610
Interest expense			(10,821	)			(14,135	)
Other income (expense), net			755				(196	)
Total other (expense) income, net			(232	)			9,279
Loss from continuing operations before income taxes			(29,159	)			(66,887	)
Income taxes			159				150
Loss from continuing operations			(29,000	)			(66,737	)
Income from discontinued operations			-				5,070
Net loss		$	(29,000	)		$	(61,667	)
Basic and diluted earnings per limited partner unit:
Loss from continuing operations		$	(0.58	)		$	(1.35	)
Income from discontinued operations			-				0.10
Net loss		$	(0.58	)		$	(1.25	)
Weighted average limited partner units outstanding (basic and diluted)			49,027				48,795
Distributions declared per unit		$	-			$	0.50

 

 See accompanying notes to unaudited condensed consolidated financial statements.

 

  

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Changes in Owners’ Equity 

(In thousands) 

(Unaudited) 

 

		Common Unitholders				General Partner Interest				Total Owners' Equity
Balance, December 31, 2015		$	1,011,509			$	(12,950	)		$	998,559
Distributions			(3,793	)			(75	)			(3,868	)
Equity–based compensation			1,568				32				1,600
Net loss			(28,420	)			(580	)			(29,000	)
Balance, March 31, 2016		$	980,864			$	(13,573	)		$	967,291

 

		Common Unitholders				General Partner Interest				Total Owners' Equity
Balance, December 31, 2014		$	1,077,826			$	(11,713	)		$	1,066,113
Contribution from general partner			-				91				91
Distributions			(24,777	)			(497	)			(25,274	)
Equity–based compensation			4,853				99				4,952
Net loss			(60,434	)			(1,233	)			(61,667	)
Balance, March 31, 2015		$	997,468			$	(13,253	)		$	984,215

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

  

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Cash Flows 

(In thousands) 

(Unaudited) 

 

		Three Months Ended
		March 31,
		2016				2015
Cash flows from operating activities:
Net loss		$	(29,000	)		$	(61,667	)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Income from discontinued operations			-				(5,070	)
Amortization of volumetric production payment liability			(1,020	)			-
Accretion expense on obligations			2,040				1,201
Depreciation, depletion and amortization			28,205				25,896
Equity–based compensation cost			1,600				4,952
Impairment of oil and natural gas properties			687				58,173
Gain on sales of oil and natural gas properties			-				(537	)
Gain on derivatives, net			(9,834	)			(23,610	)
Cash settlements of matured derivative contracts			18,350				30,533
Other			413				355
Changes in operating assets and liabilities:
Accounts receivable			10,909				9,151
Other current assets			(178	)			82
Accounts payable and accrued liabilities			3,520				5,799
Income taxes			(11,318	)			-
Other, net			(138	)			-
Net cash flows provided by operating activities			14,236				45,258
Cash flows from investing activities:
Additions to oil and natural gas properties			(7,828	)			(25,577	)
Proceeds from sale of oil and natural gas properties			2,420				774
Cash settlements from acquired derivative contracts			1,475				-
Other			18				18
Net cash flows used in investing activities			(3,915	)			(24,785	)
Cash flows from financing activities:
Repayment of long-term debt borrowings			(28,000	)			-
Long–term debt borrowings			5,000				10,000
Loan costs incurred			-				(3,277	)
Contributions from general partner			-				91
Distributions paid			(3,868	)			(25,274	)
Net cash flows used in financing activities			(26,868	)			(18,460	)
(Decrease) increase in cash and cash equivalents			(16,547	)			2,013
Cash and cash equivalents – beginning of year			20,415				8,255
Cash and cash equivalents – end of period		$	3,868			$	10,268

  

See accompanying notes to unaudited condensed consolidated financial statements.

 

  

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements

 

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS 

 

Nature of Operations 

 

EV Energy Partners, L.P. together with its wholly owned subsidiaries (“we,” “our” or “us”) is a publicly held limited partnership. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership. EnerVest and its affiliates also have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights.  

 

Basis of Presentation 

 

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2015. 

 

All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.

 

Subsequent Events

 

In April 2016, we redeemed $72.9 million of our 8% senior notes due 2019 for $30.1 million.

 

We evaluated subsequent events for appropriate accounting and disclosure through the date these unaudited condensed consolidated financial statements were issued.

  

NOTE 2. EQUITY–BASED COMPENSATION  

 

We grant various forms of equity–based awards to employees, consultants and directors of EV Management and its affiliates who perform services for us. These equity–based awards consist of phantom units and performance units.  

 

We estimated the fair value of the phantom units using the Black–Scholes option pricing model. Compensation cost is recognized for these phantom units on a straight–line basis over the service period and is net of estimated forfeitures. These phantom units are subject to graded vesting over a four year period. We recognized compensation cost related to these phantom units of $1.6 million and $4.7 million in the three months ended March 31, 2016 and 2015, respectively. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

 

As of March 31, 2016, there was $12.8 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.4 years.

 

In September 2011, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates. These performance units were fully vested as of January 2015, and we recognized compensation cost related to these performance units of $0.2 million in the three months ended March 31, 2015. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

 

  

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 3. ACQUISITIONS

 

In October 2015, we made the following acquisitions from certain institutional partnerships managed by EnerVest, a related party:

 

·

we acquired Belden & Blake Corporation (“Belden”) for $111.1 million;

 

·

we acquired oil and natural gas properties in the Austin Chalk for $25.9 million; and

 

·

we acquired oil and natural gas properties in the Appalachian Basin and the San Juan Basin for $122.0 million.

 

These acquisitions were not accounted for as common control transactions as EnerVest does not control the institutional partnerships that sold the oil and natural gas properties.

 

As part of the acquisition of oil and natural gas properties in the San Juan Basin, we assumed an obligation to deliver approximately 2.4 billion cubic feet (“Bcf”) of natural gas through December 31, 2016 under previously existing volumetric production payment (“VPP”) agreements. Under these agreements, certain of these oil and natural gas properties are subject to fixed–term overriding royalty interests which had been conveyed to the VPP purchaser. While we are obligated under these agreements to produce and deliver to the purchaser its portion of future natural gas production from these oil and natural gas properties, we retain control of these oil and natural gas properties and rights to future development drilling. If production from the oil and natural gas properties subject to the VPP is inadequate to deliver the natural gas provided for in the VPP, we have an obligation to make up the shortfall in accordance with the provisions of the agreements. At March 31, 2016 and December 31, 2015, the remaining obligation under these agreements was approximately 1.4 Bcf and 1.9 Bcf, respectively, of natural gas.

 

At March 31, 2016 and December 31, 2015, we have recorded a liability of $3.0 million and $4.0 million, respectively, which is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets, for the cost to produce and deliver to the VPP purchasers their portion of future natural gas production from these oil and natural gas properties. In the three months ended March 31, 2016, we recorded $0.1 million of accretion expense related to this VPP obligation.

 

We accounted for these acquisitions as business combinations. The following table reflects pro forma revenues and net income for the three months ended March 31, 2015 as if these acquisitions had taken place on January 1, 2015. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.

 

		Three Months
		Ended
		March 31,
		2015
Revenues:
Historical		$	47,242
Belden			8,112
Austin Chalk			3,212
Appalachian and San Juan Basins			7,965
Pro forma revenues		$	66,531
Net income (loss):
Historical		$	(61,667	)
Belden			(623	)
Austin Chalk			573
Appalachian and San Juan Basins			(42	)
Pro forma net loss		$	(61,759	)

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 4. RISK MANAGEMENT 

 

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates. As such, future earnings are subject to fluctuation due to changes in the market prices of oil, natural gas and natural gas liquids and interest rates. We use derivatives to reduce our risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates. Our policies do not permit the use of derivatives for speculative purposes.  

 

We have elected not to designate any of our derivatives as hedging instruments. Accordingly, changes in the fair value of our derivatives are recorded immediately to operations as “Gain on derivatives, net” in our unaudited condensed consolidated statements of operations.  

 

As of March 31, 2016, we had entered into commodity contracts with the following terms: 

 

Period Covered		Hedged Volume				Weighted Average Fixed Price
Oil (MBbls):
Swaps – April 2016			30.0			$	90.14
Swaps – May 2016 to September 2016			459.0				57.68
Swaps – October 2016 to December 2016			92.0				90.14
Natural Gas (MmmBtus):
Swaps – April 2016 to December 2016			29,975.0				3.57
Swaps – 2017			32,850.0				3.07
Natural Gas Liquids (MBbls):
Swap – April 2016 to December 2016			2.8				9.14

 

As of March 31, 2016, we had entered into interest rate swaps with the following terms: 

 

Period Covered		Notional Amount				Floating Rate		Fixed Rate
January 2017 – December 2017		$	100,000			1 Month LIBOR			1.039	%
January 2018 – September 2020			100,000			1 Month LIBOR			1.795	%

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

The following table sets forth the fair values and classification of our outstanding derivatives:

 

										Net Amounts
						Gross Amounts				of Assets
						Offset in the				Presented in the
		Gross				Unaudited				Unaudited
		Amounts of				Condensed				Condensed
		Recognized				Consolidated				Consolidated
		Assets				Balance Sheet				Balance Sheet
Derivatives:
As of March 31, 2016:
Derivative asset		$	55,434			$	(298	)		$	55,136
Long–term derivative asset			8,096				-				8,096
Total		$	63,530			$	(298	)		$	63,232
As of December 31, 2015:
Derivative asset		$	60,662			$	-			$	60,662
Long–term derivative asset			10,741				-				10,741
Total		$	71,403			$	-			$	71,403

 

										Net Amounts
						Gross Amounts				of Liabilities
						Offset in the				Presented in the
		Gross				Unaudited				Unaudited
		Amounts of				Condensed				Condensed
		Recognized				Consolidated				Consolidated
		Liabilities				Balance Sheet				Balance Sheet
Derivatives:
As of March 31, 2016:
Derivative liability		$	298			$	(298	)		$	-
Long–term derivative liability			1,820				-				1,820
Total		$	2,118			$	(298	)		$	1,820

 

We have entered into master netting arrangements with our counterparties. The amounts above are presented on a net basis in our unaudited condensed consolidated balance sheets when such amounts are with the same counterparty. In addition, we have recorded accounts payable and receivable balances related to our settled derivatives that are subject to our master netting agreements. These amounts are not included in the above table; however, under our master netting agreements, we have the right to offset these positions against our forward exposure related to outstanding derivatives.

 

Should our credit facility become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable. We could also be required to post cash collateral related to these derivatives under certain circumstances. As of March 31, 2016 and December 31, 2015, we were not required to post any collateral nor did we hold any collateral associated with our derivatives. 

 

  

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 5. FAIR VALUE MEASUREMENTS 

 

The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value.  Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities.  Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.  Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value.

 

Recurring Basis

 

The following table presents the fair value hierarchy for our assets and liabilities that are required to be measured at fair value on a recurring basis: 

 

						Fair Value Measurements at the End of the Reporting Period
						Quoted
						Prices in
						Active
						Markets				Significant
						for				Other				Significant
						Identical				Observable				Unobservable
						Assets				Inputs				Inputs
		Fair Value				(Level 1)				(Level 2)				(Level 3)
As of March 31, 2016:
Assets - Oil, natural gas and natural gas liquids derivatives		$	63,530			$	-			$	63,530			$	-
Liabilities:
Oil, natural gas and natural gas liquids derivatives		$	298			$	–			$	298			$	–
Interest rate swaps			1,820				–				1,820				–
		$	2,118			$	–			$	2,118			$	–
As of December 31, 2015:
Assets:
Oil, natural gas and natural gas liquids derivatives		$	70,356			$	-			$	70,356			$	-
Interest rate swaps			1,047				-				1,047				-
		$	71,403			$	-			$	71,403			$	-

 

Our derivatives consist of over–the–counter contracts which are not traded on a public exchange.  As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives using the income approach with inputs such as the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data, such as forward LIBOR curves. Our estimates of fair value have been determined at discrete points in time based on relevant market data. There were no changes in valuation techniques or related inputs in the three months ended March 31, 2016. 

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

Nonrecurring Basis

 

In the three months ended March 31, 2015, as a result of a reduction in estimated future net cash flows primarily caused by the continuing decrease in prices, we recognized a $58.2 million impairment charge to write down oil and natural gas properties to their fair value of $31.4 million.

 

The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from proved reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data.  

 

Financial Instruments 

 

The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long–term debt approximate fair value because of the short–term nature of the items. Derivatives are recorded at fair value (see above).  

 

The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. The estimated fair value of our senior notes due 2019 was $110.8 million and $211.9 million at March 31, 2016 and December 31, 2015, respectively, which differs from the carrying value of $423.8 million and $423.6 million at March 31, 2016 and December 31, 2015, respectively. The fair value of the senior notes due 2019 was determined using Level 2 inputs.

   

NOTE 6. ASSET RETIREMENT OBLIGATIONS 

 

We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. The changes in the aggregate ARO are as follows: 

 

		2016				2015
Balance as of January 1		$	176,933			$	105,773
Liabilities incurred			285				288
Revisions			82				(1	)
Accretion expense			1,988				1,201
Settlements and divestitures			(1,384	)			(120	)
Balance as of March 31		$	177,904			$	107,141

 

As of both March 31, 2016 and December 31, 2015, $2.9 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 7. LONG–TERM DEBT 

 

Long–term debt, net consisted of the following:

 

		March 31,				December 31,
		2016				2015
Credit facility		$	242,000			$	265,000
8.0% senior notes due 2019:
Principal outstanding			426,022				426,022
Unamortized discount and debt issuance costs (1)			(4,755	)			(5,116	)
Unaccreted premium (2)			2,525				2,708
			423,792				423,614
Total		$	665,792			$	688,614

 

(1)

Imputed interest rate of 8.47% and 8.87% for March 31, 2016 and December 31, 2015, respectively.

 

(2)

Imputed interest rate of 7.49% and 7.35% for March 31, 2016 and December 31, 2015, respectively.

 

Credit Facility 

 

As of March 31, 2016, we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility are secured by a first priority lien on substantially all of our oil and natural gas properties. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners. We also may use up to $100.0 million of available borrowing capacity for letters of credit. As of March 31, 2016, we have a $0.4 million letter of credit outstanding. The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense (“EBITDAX”) of no greater than 3.0 to 1.0. As of March 31, 2016, we were in compliance with these financial covenants. 

 

The facility does not require any repayments of amounts outstanding until it expires in February 2020. Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.38% and 2.94% at March 31, 2016 and 2015, respectively).  

 

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. As of March 31, 2016, the borrowing base under the facility was $625.0 million. The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.

 

In April 2016, we entered into an amendment to the credit facility that, among other things:

 

·

decreased the borrowing base to $450.0 million;

 

·

changed the senior secured funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, 3.0 to 1.0, (b) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0;

 

·

changed the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2018, 5.50 to 1.0, (b) for the fiscal quarters ending June 30, 2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December 31, 2018 and thereafter, 4.25 to 1.0;

 

  

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

·

added a cash interest expense to EBITDAX ratio covenant to be no less than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016, 2.5 to 1.0, (b) for the fiscal quarters ending and December 31, 2016, March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and thereafter, 1.5 to 1.0;

 

·

allowed for up to $35.0 million of cash, reduced by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due 2019; and

 

·

limited cash held by us to the greater of 5% of the current borrowing base or $30.0 million.

 

Should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our short–term liquidity.

 

8.0% Senior Notes due 2019 

 

Our senior notes due 2019 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes. Neither EV Energy Partners, L.P. nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.  

  

NOTE 8. COMMITMENTS AND CONTINGENCIES

 

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our unaudited condensed consolidated financial statements and no amounts have been accrued at March 31, 2016 or December 31, 2015.

 

NOTE 9. OWNERS’ EQUITY 

 

Units Outstanding 

 

At March 31, 2016, owners’ equity consists of 49,055,214 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest. 

 

Issuance of Units 

 

In the three months ended March 31, 2016, we issued 0.2 million common units related to the vesting of equity–based awards.

 

Cash Distributions 

 

On January 25, 2016, the board of directors of EV Management declared a $0.075 per unit distribution for the fourth quarter of 2015 on all outstanding units. The distribution of $3.9 million was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016.

 

In April 2016, the board of directors of EV Management announced that it had elected to suspend distributions to unitholders.

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 10. DISCONTINUED OPERATIONS

 

In 2015, we reclassified our unaudited condensed consolidated financial statements to reflect the operations of our midstream segment as discontinued operations due to the sales of our interest in Cardinal Gas Services, LLC in October 2014 and our interest in Utica East Ohio Midstream LLC in June 2015.

 

Summarized financial information for our midstream segment is as follows:

 

		Three Months Ended
		March 31,
		2015
Revenues		$	48,543
Operating income			24,474
Net income			24,744

 

NOTE 11. EARNINGS PER LIMITED PARTNER UNIT 

 

The following sets forth the calculation of earnings per limited partner unit: 

 

		Three Months Ended
		March 31,
		2016				2015
Loss from continuing operations		$	(29,000	)		$	(66,737	)
General partner's 2% interest in loss from continuing operations			580				1,334
Earnings attributable to unvested phantom units			-				(342	)
Limited partners' interest in loss from continuing operations		$	(28,420	)		$	(65,745	)
Earnings per limited partner unit (basic and diluted)		$	(0.58	)		$	(1.35	)
Income from discontinued operations		$	-			$	5,070
General partner's 2% interest in income from discontinued operations			-				(101	)
Limited partners' interest in income from discontinued operations		$	-			$	4,969
Earnings per limited partner unit (basic and diluted)		$	-			$	0.10
Net loss		$	(29,000	)		$	(61,667	)
General partner’s 2% interest in net loss			580				1,233
Earnings attributable to unvested phantom units			-				(342	)
Limited partners’ interest in net loss		$	(28,420	)		$	(60,776	)
Earnings per limited partner unit (basic and diluted)		$	(0.58	)		$	(1.25	)
Weighted average limited partner units outstanding (basic and diluted)			49,027				48,795

 

NOTE 12. RELATED PARTY TRANSACTIONS 

 

Pursuant to an omnibus agreement, we paid EnerVest $4.0 million and $3.3 million in the three months ended March 31, 2016 and 2015, respectively, in monthly administrative fees for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.  

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

We have entered into operating agreements with EnerVest whereby a wholly owned subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest approximately $6.1 million and $4.1 million in the three months ended March 31, 2016 and 2015, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of the costs that would have been incurred on a standalone basis. These costs are included in lease operating expenses in our unaudited condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

  

NOTE 13. OTHER SUPPLEMENTAL INFORMATION  

 

Supplemental cash flows and noncash transactions were as follows: 

 

		Three Months Ended
		March 31,
		2016				2015
Supplemental cash flows information:
Cash paid for interest		$	1,557			$	3,303
Cash paid for income taxes			11,318				-

 

		As of March 31,
		2016				2015
Noncash transaction - costs for additions to oil and natural gas properties in accounts payable and accrued liabilities		$	5,420			$	15,964

 

Accounts payable and accrued liabilities consisted of the following:

 

		March 31,				December 31,
		2016				2015
Costs for additions to oil and natural gas properties		$	5,420			$	5,212
Lease operating expenses			9,293				10,576
Interest			15,786				7,298
Production and ad valorem taxes			5,129				6,763
VPP			3,016				3,984
General and administrative expenses			1,909				2,864
Current portion of ARO			2,930				2,930
Other			1,635				3,508
Total		$	45,118			$	43,135

 

NOTE 14. NEW ACCOUNTING STANDARDS  

 

In August 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

In March 2016, the FASB issued ASU No. 2016–09, Compensation – Stock Compensation. This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. The provisions of ASU 2016–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.

 

No other new accounting pronouncements issued or effective during the three months ended March 31, 2016 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

 

 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 2015. 

 

OVERVIEW  

 

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. Our general partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware limited liability company. 

 

We operate in one reportable segment engaged in the acquisition, development and production of oil and natural gas properties and all of our operations are located in the United States.

 

As of December 31, 2015, our oil and natural gas properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Monroe Field in Northern Louisiana, and the Permian Basin. As of December 31, 2015, we had estimated net proved reserves of 22.0 MMBbls of oil, 747.0 Bcf of natural gas and 36.3 MMBbls of natural gas liquids, or 1,096.7 Bcfe, and a standardized measure of $536.4 million.

 

Current Price Environment

 

Oil, natural gas and natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously, and such prices have remained low into the three months ended March 31, 2016.

 

Factors contributing to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate to the price of oil and, accordingly, prices have fallen and are likely to continue to directionally follow the market for oil. Further, excess supply with higher volumes in storage has resulted in a further drop in pricing for natural gas liquids.

 

In the three months ended March 31, 2016, these low prices negatively affected our revenues, earnings and cash flows, and sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. A further or extended decline in prices could also adversely have a significant impact on the value and quantities of our reserves, assuming no other changes in our development plans.

 

As specified by the SEC, the prices for oil, natural gas and natural gas liquids used to calculate our reserves were the average prices during the year determined using the price on the first day of each month. The prices utilized in calculating our total estimated proved reserves at December 31, 2015 were $50.28 per Bbl of oil and $2.587 per MMBtu of natural gas. Had we used the current forward strip prices at December 31, 2015 through December 31, 2021, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 29% higher and that our reserves on an Mcfe basis would have been approximately 7% higher than our reserves calculated using SEC prices.

 

Our Response to the Current Price Environment

 

In response to continued lower prices, we took a number of actions to preserve our liquidity and financial flexibility, including:

 

·

reevaluated our common unit distribution policy and, in January 2016, announced a reduction in the quarterly distribution amount from $0.50 to $0.075 per unit;

 

  

·

reduced the amount of capital spending we dedicated to the development of our reserves by approximately 75%; and

 

·

continued to focus on reducing operating and capital costs.

 

In April 2016, we also entered into an amendment to our credit facility that, among other things:

 

·

decreased the borrowing base to $450.0 million;

 

·

changed the senior secured funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, 3.0 to 1.0, (b) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0;

 

·

changed the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2018, 5.50 to 1.0, (b) for the fiscal quarters ending June 30, 2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December 31, 2018 and thereafter, 4.25 to 1.0;

 

·

added a cash interest expense to EBITDAX ratio covenant to be no less than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016, 2.5 to 1.0, (b) for the fiscal quarters ending and December 31, 2016, March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and thereafter, 1.5 to 1.0;

 

·

allowed for up to $35.0 million of cash, reduced by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due 2019; and

 

·

limited cash held by us to the greater of 5% of the current borrowing base or $30.0 million.

 

Given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2016 relative to previous years, we have taken additional steps going forward into 2016 to continue to preserve our liquidity and financial flexibility. These steps include:

 

·

focus on managing and enhancing our base business through continued reductions in operating and capital costs;

 

·

maintain a sufficient liquidity position to manage through the current environment, which includes continuing to assess the appropriate distribution levels every quarter;

 

·

continue to evaluate strategic acquisitions of long–life, producing oil and natural gas properties; and

 

·

further realize the value of our undeveloped acreage through either alternative sources of capital, including farmouts, production payments and joint ventures, or potential monetization of acreage.

 

In April 2016, we announced that we had elected to suspend distributions to unitholders. As part of the amendment to our credit facility, we were authorized to use up to $35.0 million of cash or available borrowing base capacity to repurchase our senior notes due 2019 that would be reduced dollar for dollar for any distribution paid out for the remainder of 2016.  Since the adoption of this amendment in April 2016, we have repurchased $72.9 million of outstanding senior notes due 2019 for $30.1 million. This repurchase of our senior notes due 2019 at a discount to par will create cancellation of debt income for our unitholders.

 

As of April 29, 2016, we have $285.0 million outstanding under our credit facility and $353.1 million of our senior notes due 2019 outstanding, for a total of $638.1 million, and we have over $165.0 million of liquidity between our borrowing base capacity and cash on hand.

 

  

Business Environment

 

Our primary business objective is to provide stability and growth in cash distributions per unit over time. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

·

the prices at which we will sell our oil, natural gas liquids and natural gas production;

 

·

our ability to hedge commodity prices;

 

·

the amount of oil, natural gas liquids and natural gas we produce; and

 

·

the level of our operating and administrative costs.

 

In order to mitigate the impact of lower prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of price volatility on our cash flows. Although we have entered into derivative contracts covering a portion of our future production through December 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices at which we can enter into derivative contracts for additional volumes in the future. We have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. An extended period of depressed commodity prices would alter our acquisition and development plans, adversely affect our growth strategy and our ability to access additional capital in the capital markets and reduce the cash we have available to pay distributions, which may require us to further reduce our quarterly distribution amount.

 

The primary factors affecting our production levels are capital availability, including planned reductions in capital spending for 2016, our ability to make accretive acquisitions, the success of our drilling program and our inventory of drilling prospects. In addition, as initial reservoir pressures are depleted, production from our wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain our focus on the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

 

We focus our efforts on increasing our reserves and production while controlling costs at a level that is appropriate for long–term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.

 

  

RESULTS OF OPERATIONS 

 

		Three Months Ended
		March 31,
		2016				2015
Production data:
Oil (MBbls)			317				241
Natural gas liquids (MBbls)			602				582
Natural gas (MMcf)			12,818				10,588
Net production (MMcfe)			18,331				15,525
Average sales price per unit:
Oil (Bbl)		$	29.12			$	44.02
Natural gas liquids (Bbl)			12.22				15.12
Natural gas (Mcf)			1.65				2.55
Mcfe			2.06				2.99
Average unit cost per Mcfe:
Production costs:
Lease operating expenses		$	1.58			$	1.52
Production taxes			0.09				0.11
Total			1.67				1.63
Depreciation, depletion and amortization			1.54				1.67
General and administrative expenses			0.46				0.80

 

Net loss for the three months ended March 31, 2016 was $29.0 million compared with $61.7 million for the three months ended March 31, 2015. The significant factors in this change were (i) a $57.5 million decrease in impairment of oil and natural gas properties, offset by (ii) a $13.8 million unfavorable change in gain on derivatives and (iii) a $9.0 million decrease in total revenues.

 

Oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2016 totaled $37.7 million, a decrease of $8.7 million compared with the three months ended March 31, 2015. This was the result of a decrease of $14.8 million related to lower prices offset by an increase of $6.1 million related to increased oil, natural gas and natural gas liquids production. 

 

Lease operating expenses for the three months ended March 31, 2016 increased $5.4 million compared with the three months ended March 31, 2015 as the result of $4.4 million from increased production and $1.0 million from a higher unit cost per Mcfe. Lease operating expenses were $1.58 per Mcfe in the three months ended March 31, 2016 compared with $1.52 per Mcfe in the three months ended March 31, 2015.  

  

Depreciation, depletion and amortization (“DD&A”) for the three months ended March 31, 2016 increased $2.3 million compared with the three months ended March 31, 2015 as a result of $4.3 million from increased production offset by $2.0 million from a lower unit cost per Mcfe. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2015. DD&A was $1.54 per Mcfe in the three months ended March 31, 2016 compared with $1.67 per Mcfe in the three months ended March 31, 2015.  

 

General and administrative expenses for the three months ended March 31, 2016 totaled $8.4 million, a decrease of $4.0 million compared with the three months ended March 31, 2015. This decrease is primarily the result of (i) $3.3 million of lower equity compensation costs, of which $2.3 million related to the accelerated vesting of the phantom units of a former officer in the three months ended March 31, 2015; (ii) a $1.3 million decrease in compensation costs, of which $0.8 million related to the vesting of our phantom units under our equity compensation plan; offset by (iii) $0.7 million of higher fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.46 per Mcfe in the three months ended March 31, 2016 compared with $0.80 per Mcfe in the three months ended March 31, 2015.  

 

In the three months ended March 31, 2016, we incurred leasehold impairment charges of $0.7 million. In the three months ended March 31, 2015, as a result of a continued reduction in estimated future net cash flows primarily caused by the decrease in prices, we incurred impairment charges of $58.2 million to write down oil and natural gas properties to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data.

 

  

Gain on derivatives, net was $9.8 million for the three months ended March 31, 2016 compared with $23.6 million for the three months ended March 31, 2015. This change was attributable to decreases in future oil and natural gas prices and the impact of derivative contracts with more favorable terms that expired as of December 31, 2015. The 12 month forward price at March 31, 2016 for oil averaged $38.56 per Bbl compared with $40.45 at December 31, 2015, and the 12 month forward prices at March 31, 2016 for natural gas averaged $2.19 per MmBtu compared with $2.49 at December 31, 2015. The 12 month forward price at March 31, 2015 for oil averaged $53.30 per Bbl compared with $56.46 at December 31, 2014, and the 12 month forward prices at March 31, 2015 for natural gas averaged $2.91 per MmBtu compared with $3.03 at December 31, 2014.

 

Interest expense for the three months ended March 31, 2016 decreased $3.3 million compared with the three months ended March 31, 2015 due to $5.6 million from a lower weighted average long–term debt balance offset by $2.3 million from a higher weighted average effective interest rate.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our unitholders and general partner and working capital needs.

 

In response to continued lower prices, we took a number of actions to preserve our liquidity and financial flexibility, and, as of April 29, 2016, we have over $165.0 million of liquidity between our borrowing base capacity and cash on hand. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2016 relative to previous years, we have taken additional steps going forward into 2016 to continue to preserve our liquidity and financial flexibility. These steps include:

 

·

focus on managing and enhancing our base business through continued reductions in operating and capital costs;

 

·

maintain a sufficient liquidity position to manage through the current environment, which includes continuing to assess the appropriate distribution levels every quarter;

 

·

continue to evaluate strategic acquisitions of long–life, producing oil and natural gas properties; and

 

·

further realize the value of our undeveloped acreage through either alternative sources of capital, including farmouts, production payments and joint ventures, or potential monetization of acreage.

 

For 2016, we believe that cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget, pay distributions to our unitholders and general partner and satisfy our short–term liquidity needs.

 

We may also utilize borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long–term liquidity needs. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

 

Long–term Debt

 

As of March 31, 2016, we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of March 31, 2016, the borrowing base was $625.0 million, and we had $242.0 million outstanding.

 

In April 2016, we entered into an amendment to the credit facility that, among other things, decreased the borrowing base to $450.0 million. Although the borrowing base under the credit facility was reduced, we believe we will maintain sufficient short–term liquidity. However, should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our short–term liquidity.

 

  

As of March 31, 2016, we have $426.0 million in aggregate principal amount outstanding of our 8.0% senior notes due 2019. As of March 31, 2016, the aggregate carrying amount of the senior notes due 2019 was $423.8 million.

 

In April 2016, we repurchased $72.9 million of outstanding senior notes due 2019 for $30.1 million. This repurchase of our senior notes due 2019 at a discount to par will create cancellation of debt income for our unitholders.

 

As of April 29, 2016, we have $285.0 million outstanding under our credit facility and $353.1 million of our senior notes due 2019 outstanding, for a total of $638.1 million.

 

For additional information about our long–term debt, such as interest rates and covenants, please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein.

 

Cash and Short–term Investments

 

At March 31, 2016, we had $3.9 million of cash and short–term investments, which included $3.2 million of short–term investments.  With regard to our short–term investments, we invest in money market accounts with major financial institutions.  

 

Counterparty Exposure

 

All of our derivative contracts are with major financial institutions who are also lenders under our credit facility.  Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of March 31, 2016, all of our counterparties have performed pursuant to their derivative contracts.

 

Cash Flows

 

Cash flows provided by (used in) type of activity were as follows:

 

		Three Months Ended
		March 31,
		2016				2015
Operating activities		$	14,236			$	45,258
Investing activities			(3,915	)			(24,785	)
Financing activities			(26,868	)			(18,460	)

 

Operating Activities

 

Cash flows from operating activities provided $14.2 million and $45.3 million in the three months ended March 31, 2016 and 2015, respectively. The significant factors in the change were $12.2 million of decreased cash settlements from our matured derivative contracts, an $11.3 million federal tax payment related to the conversion of an acquired corporation to a single member LLC and a $9.0 million decrease in total revenues.

 

Investing Activities

 

During the three months ended March 31, 2016, we spent $7.8 million for additions to our oil and natural gas properties and received $2.4 million from the sale of certain oil and natural gas wells and $1.5 million in cash settlements from acquired derivative contracts. During the three months ended March 31, 2015, we spent $25.6 million for additions to our oil and natural gas properties and received $0.8 million in proceeds from the sale of oil and natural gas properties.

 

 

Financing Activities

 

During the three months ended March 31, 2016, we received $5.0 million from borrowings under our credit facility, repaid $28.0 million of long–term debt borrowings and paid distributions of $3.9 million to holders of our common units, phantom units and our general partner.

 

During the three months ended March 31, 2015, we received $10.0 million from borrowings under our credit facility, incurred loan costs of $3.3 million related to the amendment of our credit facility and paid distributions of $25.3 million to holders of our common units, phantom units and our general partner.

 

FORWARD–LOOKING STATEMENTS

 

This Form 10–Q contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward–looking statement”). These forward–looking statements relate to, among other things, the following:

 

·

our future financial and operating performance and results, and our ability to pay distributions;

 

·

our business strategy and plans, and future capital expenditures, including plans to further realize value of our undeveloped acreage;

 

·

our estimated net proved reserves, PV–10 value and standardized measure;

 

·

market prices;

 

·

our future derivative activities; and

 

·

our plans and forecasts.

 

We have based these forward–looking statements on our current assumptions, expectations and projections about future events.

 

The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward–looking” information. We do not undertake any obligation to update or revise publicly any forward–looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10–Q including, but not limited to:

 

·

fluctuations in prices of oil, natural gas and natural gas liquids and the length of time commodity prices remain depressed;

 

·

significant disruptions in the financial markets;

 

·

future capital requirements and availability of financing;

 

·

uncertainty inherent in estimating our reserves;

 

·

risks associated with drilling and operating wells;

 

·

discovery, acquisition, development and replacement of reserves;

 

·

cash flows and liquidity;

 

·

timing and amount of future production of oil, natural gas and natural gas liquids;

 

  

·

marketing of oil, natural gas and natural gas liquids;

 

·

developments in oil and natural gas producing countries;

 

·

competition;

 

·

general economic conditions;

 

·

governmental regulations;

 

·

activities taken or non–performance by third parties, including suppliers, contractors, operators, transporters and purchasers of our production and counterparties to our derivative financial instruments;

 

·

hedging decisions, including whether or not to enter into derivative financial instruments;

 

·

actions of third party co–owners of interest in properties in which we also own an interest;

 

·

fluctuations in interest rates and the value of the U.S. dollar in international currency markets; and

 

·

our ability to effectively integrate companies and properties that we acquire.

 

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10–K for the year ended December 31, 2015. 

 

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil, natural gas and natural gas liquids. Declines in prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower prices also may reduce the amount of oil, natural gas or natural gas liquids that we can produce economically. A decline in prices could have a material adverse effect on the estimated value and estimated quantities of our reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes.

 

We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

 

Commodity Price Risk

 

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas production. We have used, and expect to continue to use, commodity contracts to reduce our risk of changes in the prices of oil, natural gas and natural gas liquids. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre–existing or anticipated sales of oil, natural gas and natural gas liquids.

 

We have entered into commodity contracts to hedge a portion of our anticipated oil and natural gas production through December 2017. As of March 31, 2016, we have commodity contracts covering approximately 67% of our production attributable to our estimated net proved reserves from April 2016 through December 2017, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

 

  

The fair value of our commodity contracts at March 31, 2016 was a net asset of $63.2 million. A 10% change in oil and natural gas prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $18.4 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

Interest Rate Risk

 

Our floating rate credit facility and interest rate swaps also expose us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. If interest rates on our facility increased by 1%, interest expense for the three months ended March 31, 2016 would have increased by approximately $0.6 million. The fair value of our interest rate swaps at March 31, 2016 was a liability of $1.8 million. A 1% change in interest rates with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such interest rate swaps) of our interest rate swaps of approximately $1.3 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

ITEM 4. CONTROLS AND PROCEDURES

 

Evaluation of Disclosure Controls and Procedures

 

In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2016 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

 

Change in Internal Controls Over Financial Reporting

 

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

PART II. OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

 

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our unaudited condensed consolidated financial statements.

 

ITEM 1A. RISK FACTORS

 

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10–K for the year ended December 31, 2015.

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

None.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

 

None.

 

  

ITEM 4. MINE SAFETY DISCLOSURES

 

Not applicable.

 

ITEM 5. OTHER INFORMATION

 

None.

 

ITEM 6. EXHIBITS 

 

The exhibits listed below are filed or furnished as part of this report: 

 

3.1

First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.2

First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.3

Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.4

First Amendment dated April 15, 2008 to First Amended and Restated Partnership Agreement of EV Energy Partners, L.P., effective as of January 1, 2007 (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 18, 2008).

 

4.1

Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

 

10.1

Ninth Amendment dated April 1, 2016 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 4, 2016).

 

+31.1

Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer.

 

+31.2

Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer.

 

+32.1

Section 1350 Certification of Chief Executive Officer.

 

+32.2

Section 1350 Certification of Chief Financial Officer.

 

+101

Interactive Data Files.

 

+

Filed herewith

 

  

SIGNATURES 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  

 

	EV Energy Partners, L.P.
	(Registrant)
Date:  May 9, 2016	By:	/s/ NICHOLAS BOBROWSKI
		Nicholas Bobrowski
		Vice President and Chief Financial Officer

 

 

EXHIBIT INDEX 

 

3.1

First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.2

First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.3

Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.4

First Amendment dated April 15, 2008 to First Amended and Restated Partnership Agreement of EV Energy Partners, L.P., effective as of January 1, 2007 (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 18, 2008).

 

4.1

Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

 

10.1

Ninth Amendment dated April 1, 2016 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 4, 2016).

 

+31.1

Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer.

 

+31.2

Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer.

 

+32.1

Section 1350 Certification of Chief Executive Officer.

 

+32.2

Section 1350 Certification of Chief Financial Officer.

 

+101

Interactive Data Files.

 

+ Filed herewith 

 

 

Exhibit 31.1 

 

CERTIFICATIONS 

 

I, Michael E. Mercer, certify that:  

 

1.

I have reviewed this quarterly report on Form 10–Q of EV Energy Partners, L.P.;

 

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

 

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

  

Date: May 9, 2016	/s/ MICHAEL E. MERCER
	Michael E. Mercer
	Chief Executive Officer of EV Management LLC,
	general partner of EV Energy GP, L.P.,
	general partner of EV Energy Partners, L.P.

 

 

Exhibit 31.2 

 

CERTIFICATIONS 

 

I, Nicholas Bobrowski, certify that:  

 

1.

I have reviewed this quarterly report on Form 10–Q of EV Energy Partners, L.P.;

 

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

 

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

  

Date: May 9, 2016	/s/ NICHOLAS BOBROWSKI
	Nicholas Bobrowski
	Chief Financial Officer of EV Management LLC,
	general partner of EV Energy GP, L.P.,
	general partner of EV Energy Partners, L.P.

 

 

Exhibit 32.1

 

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 

  

In connection with the accompanying report on Form 10–Q for the period ended March 31, 2016 of EV Energy Partners, L.P. (the “Partnership”) and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael E. Mercer, Chief Executive Officer of EV Management, LLC, the general partner of EV Energy GP, L.P., the general partner of the Partnership, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002, that: 

  

•

the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

  

•

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

Date: May 9, 2016	/s/ MICHAEL E. MERCER
	Michael E. Mercer
	Chief Executive Officer of EV Management LLC,
	general partner of EV Energy GP, L.P.,
	general partner of EV Energy Partners, L.P.

 

 

 

Exhibit 32.2 

 

 

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 

  

In connection with the accompanying report on Form 10–Q for the period ended March 31, 2016 of EV Energy Partners, L.P. (the “Partnership”) and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Nicholas Bobrowski, Chief Financial Officer of EV Management, LLC, the general partner of EV Energy GP, L.P., the general partner of the Partnership, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002, that: 

  

•

the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

  

•

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

Date: May 9, 2016	/s/ NICHOLAS BOBROWSKI
	Nicholas Bobrowski
	Chief Financial Officer of EV Management LLC,
	general partner of EV Energy GP, L.P.,
	general partner of EV Energy Partners, L.P.

 

v3.4.0.3

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 29, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Trading Symbol	evep
Entity Registrant Name	EV Energy Partners, LP
Entity Central Index Key	0001361937
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		49,055,214

v3.4.0.3

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 3,868	$ 20,415
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	18,226	24,285
Other	2,084	7,137
Derivative asset	55,136	60,662
Other current assets	3,112	3,057
Total current assets	82,426	115,556
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; March 31, 2016, $999,704; December 31, 2015, $971,499	1,766,188	1,790,455
Other property, net of accumulated depreciation and amortization; March 31, 2016, $978; December 31, 2015, $970	1,029	1,019
Long-term derivative asset	8,096	10,741
Other assets	5,644	5,831
Total assets	1,863,383	1,923,602
Current liabilities:
Accounts payable and accrued liabilities	45,118	43,135
Related party	6,526	5,952
Income taxes	339	11,657
Total current liabilities	51,983	60,744
Asset retirement obligations	174,974	174,003
Long-term debt	665,792	688,614
Long-term derivative liability	1,820
Other long-term liabilities	1,523	1,682
Owners' equity:
Common unitholders - 49,055,214 units and 48,871,399 units issued and outstanding as of March 31, 2016 and December 31, 2015, respectively	980,864	1,011,509
General partner interest	(13,573)	(12,950)
Total owners' equity	967,291	998,559
Total liabilities and owners' equity	$ 1,863,383	$ 1,923,602

v3.4.0.3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Oil and natural gas properties, accumulated depreciation, depletion and amortization	$ 999,704	$ 971,499
Other property, accumulated depreciation and amortization	$ 978	$ 970
Common Unitholders [Member]
Common unitholders, units issued	49,055,214	48,871,399
Common unitholders, units outstanding	49,055,214	48,871,399

v3.4.0.3

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues:
Oil, natural gas and natural gas liquids revenues	$ 37,739	$ 46,425
Transportation and marketing-related revenues	511	817
Total revenues	38,250	47,242
Operating costs and expenses:
Lease operating expenses	28,915	23,524
Cost of purchased natural gas	336	574
Dry hole and exploration costs	130	414
Production taxes	1,671	1,748
Accretion expense on obligations	2,040	1,201
Depreciation, depletion and amortization	28,205	25,896
General and administrative expenses	8,378	12,415
Impairment of oil and natural gas properties	687	58,173
Gain on settlement of contract	(3,185)
Gain on sales of oil and natural gas properties		(537)
Total operating costs and expenses	67,177	123,408
Operating loss	(28,927)	(76,166)
Other income (expense), net:
Gain on derivatives, net	9,834	23,610
Interest expense	(10,821)	(14,135)
Other income (expense), net	755	(196)
Total other (expense) income, net	(232)	9,279
Loss from continuing operations before income taxes	(29,159)	(66,887)
Income taxes	159	150
Loss from continuing operations	(29,000)	(66,737)
Income from discontinued operations		5,070
Net loss	$ (29,000)	$ (61,667)
Basic and diluted earnings per limited partner unit:
Loss per limited partner unit (basic and diluted), continuing	$ (0.58)	$ (1.35)
Earnings per limited partner unit (basic and diluted), discontinued		0.10
Net loss	$ (0.58)	$ (1.25)
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding - basic and diluted	49,027	48,795
Distributions declared per unit		$ 0.50

v3.4.0.3

Condensed Consolidated Statements of Changes in Owners' Equity - USD ($) $ in Thousands	Common Unitholders [Member]	General Partner Interest [Member]	Total
Beginning Balance at Dec. 31, 2014	$ 1,077,826	$ (11,713)	$ 1,066,113
Contributions from general partner		91	91
Distributions	(24,777)	(497)	(25,274)
Equity-based compensation	4,853	99	4,952
Net income (loss)	(60,434)	(1,233)	(61,667)
Ending Balance at Mar. 31, 2015	997,468	(13,253)	984,215
Beginning Balance at Dec. 31, 2015	1,011,509	(12,950)	998,559
Distributions	(3,793)	(75)	(3,868)
Equity-based compensation	1,568	32	1,600
Net income (loss)	(28,420)	(580)	(29,000)
Ending Balance at Mar. 31, 2016	$ 980,864	$ (13,573)	$ 967,291

v3.4.0.3

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities:
Net loss	$ (29,000)	$ (61,667)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Income from discontinued operations		(5,070)
Amortization of volumetric production payment liability	(1,020)
Accretion expense on obligations	2,040	1,201
Depreciation, depletion and amortization	28,205	25,896
Equity-based compensation cost	1,600	4,952
Impairment of oil and natural gas properties	687	58,173
Gain on sales of oil and natural gas properties		(537)
Gain on derivatives, net	(9,834)	(23,610)
Cash settlements of matured derivatives contracts	18,350	30,533
Other	413	355
Changes in operating assets and liabilities:
Accounts receivable	10,909	9,151
Other current assets	(178)	82
Accounts payable and accrued liabilities	3,520	5,799
Income taxes	(11,318)
Other, net	(138)
Net cash flows provided by operating activities	14,236	45,258
Cash flows from investing activities:
Additions to oil and natural gas properties	(7,828)	(25,577)
Proceeds from sale of oil and natural gas properties	2,420	774
Cash settlements from acquired derivative contracts	1,475
Other	18	18
Net cash flows used in investing activities	(3,915)	(24,785)
Cash flows from financing activities:
Repayment of long-term debt borrowings	(28,000)
Long-term debt borrowings	5,000	10,000
Loan costs incurred		(3,277)
Contributions from general partner		91
Distributions paid	(3,868)	(25,274)
Net cash flows used in financing activities	(26,868)	(18,460)
(Decrease) increase in cash and cash equivalents	(16,547)	2,013
Cash and cash equivalents - beginning of year	20,415	8,255
Cash and cash equivalents - end of period	$ 3,868	$ 10,268

v3.4.0.3

ORGANIZATION AND NATURE OF BUSINESS	3 Months Ended
	Mar. 31, 2016
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
ORGANIZATION AND NATURE OF BUSINESS	NOTE 1. ORGANIZATION AND NATURE OF BUSINESS    Nature of Operations    EV Energy Partners, L.P. together with its wholly owned subsidiaries (“we,” “our” or “us”) is a publicly held limited partnership.  Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company.  EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership.  EnerVest and its affiliates also have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights.         Basis of Presentation    Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”).  Accordingly, certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted.  We believe that the presentations and disclosures herein are adequate to make the information not misleading.  The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods.  The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.  These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2015.    All intercompany accounts and transactions have been eliminated in consolidation.  In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.  Subsequent Events  In April 2016, we redeemed $72.9 million of our 8% senior notes due 2019 for $30.1 million.  We evaluated subsequent events for appropriate accounting and disclosure through the date these unaudited condensed consolidated financial statements were issued.

v3.4.0.3

EQUITY-BASED COMPENSATION	3 Months Ended
	Mar. 31, 2016
EQUITY-BASED COMPENSATION [Abstract]
EQUITY-BASED COMPENSATION	NOTE 2. EQUITY–BASED COMPENSATION      We grant various forms of equity–based awards to employees, consultants and directors of EV Management and its affiliates who perform services for us.  These equity–based awards consist of phantom units and performance units.     We estimated the fair value of the phantom units using the Black–Scholes option pricing model.  Compensation cost is recognized for these phantom units on a straight–line basis over the service period and is net of estimated forfeitures.  These phantom units are subject to graded vesting over a four year period.  We recognized compensation cost related to these phantom units of $1.6 million and $4.7 million in the three months ended March 31, 2016 and 2015, respectively.  These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.   As of March 31, 2016, there was $12.8 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.4 years.    In September 2011, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates.  These performance units were fully vested as of January 2015, and we recognized compensation cost related to these performance units of $0.2 million in the three months ended March 31, 2015.  These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.   

v3.4.0.3

ACQUISITIONS	3 Months Ended
	Mar. 31, 2016
ACQUISITIONS [Abstract]
ACQUISITIONS	NOTE 3. ACQUISITIONS  In October 2015, we made the following acquisitions from certain institutional partnerships managed by EnerVest, a related party:  · we acquired Belden & Blake Corporation (“Belden”) for $111.1 million;  · we acquired oil and natural gas properties in the Austin Chalk for $25.9 million; and  · we acquired oil and natural gas properties in the Appalachian Basin and the San Juan Basin for $122.0 million.  These acquisitions were not accounted for as common control transactions as EnerVest does not control the institutional partnerships that sold the oil and natural gas properties.  As part of the acquisition of oil and natural gas properties in the San Juan Basin, we assumed an obligation to deliver approximately 2.4 billion cubic feet (“Bcf”) of natural gas through December 31, 2016 under previously existing volumetric production payment (“VPP”) agreements.  Under these agreements, certain of these oil and natural gas properties are subject to fixed–term overriding royalty interests which had been conveyed to the VPP purchaser.  While we are obligated under these agreements to produce and deliver to the purchaser its portion of future natural gas production from these oil and natural gas properties, we retain control of these oil and natural gas properties and rights to future development drilling.  If production from the oil and natural gas properties subject to the VPP is inadequate to deliver the natural gas provided for in the VPP, we have an obligation to make up the shortfall in accordance with the provisions of the agreements.  At March 31, 2016 and December 31, 2015, the remaining obligation under these agreements was approximately 1.4 Bcf and 1.9 Bcf, respectively, of natural gas.  At March 31, 2016 and December 31, 2015, we have recorded a liability of $3.0 million and $4.0 million, respectively, which is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets, for the cost to produce and deliver to the VPP purchasers their portion of future natural gas production from these oil and natural gas properties.  In the three months ended March 31, 2016, we recorded $0.1 million of accretion expense related to this VPP obligation.  We accounted for these acquisitions as business combinations.  The following table reflects pro forma revenues and net income for the three months ended March 31, 2015 as if these acquisitions had taken place on January 1, 2015.  These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.                    Three Months    Ended    March 31,    2015 Revenues:       Historical   $ 47,242  Belden     8,112  Austin Chalk     3,212  Appalachian and San Juan Basins     7,965  Pro forma revenues   $ 66,531         Net income (loss):       Historical   $ (61,667) Belden     (623) Austin Chalk     573  Appalachian and San Juan Basins     (42) Pro forma net loss   $ (61,759) 

v3.4.0.3

RISK MANAGEMENT	3 Months Ended
	Mar. 31, 2016
RISK MANAGEMENT [Abstract]
RISK MANAGEMENT	NOTE 4. RISK MANAGEMENT    Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids.  In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates.  As such, future earnings are subject to fluctuation due to changes in the market prices of oil, natural gas and natural gas liquids and interest rates.  We use derivatives to reduce our risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates.  Our policies do not permit the use of derivatives for speculative purposes.      We have elected not to designate any of our derivatives as hedging instruments.  Accordingly, changes in the fair value of our derivatives are recorded immediately to operations as “Gain on derivatives, net” in our unaudited condensed consolidated statements of operations.      As of March 31, 2016, we had entered into commodity contracts with the following terms:                              Period Covered   Hedged Volume   Weighted Average Fixed Price Oil (MBbls):           Swaps – April 2016   30.0    $ 90.14  Swaps – May 2016 to September 2016   459.0      57.68  Swaps – October 2016 to December 2016   92.0      90.14             Natural Gas (MmmBtus):           Swaps – April 2016 to December 2016   29,975.0      3.57  Swaps – 2017   32,850.0      3.07             Natural Gas Liquids (MBbls):           Swap – April 2016 to December 2016   2.8      9.14              As of March 31, 2016, we had entered into interest rate swaps with the following terms:                                   Period Covered   Notional Amount   Floating Rate   Fixed Rate January 2017 – December 2017   $ 100,000    1 Month LIBOR   1.039%  January 2018 – September 2020     100,000    1 Month LIBOR   1.795%      The following table sets forth the fair values and classification of our outstanding derivatives:                                                           Net Amounts            Gross Amounts     of Assets            Offset in the     Presented in the      Gross     Unaudited     Unaudited      Amounts of     Condensed     Condensed      Recognized     Consolidated     Consolidated      Assets     Balance Sheet     Balance Sheet Derivatives:                   As of March 31, 2016:                   Derivative asset   $ 55,434    $ (298)   $ 55,136  Long–term derivative asset     8,096       -     8,096  Total   $ 63,530    $ (298)   $ 63,232                     As of December 31, 2015:                   Derivative asset   $ 60,662    $  -   $ 60,662  Long–term derivative asset     10,741       -     10,741  Total   $ 71,403    $  -   $ 71,403                                                           Net Amounts            Gross Amounts     of Liabilities            Offset in the     Presented in the      Gross     Unaudited     Unaudited      Amounts of     Condensed     Condensed      Recognized     Consolidated     Consolidated      Liabilities     Balance Sheet     Balance Sheet Derivatives:                   As of March 31, 2016:                   Derivative liability   $ 298    $ (298)   $  - Long–term derivative liability     1,820       -     1,820  Total   $ 2,118    $ (298)   $ 1,820   We have entered into master netting arrangements with our counterparties. The amounts above are presented on a net basis in our unaudited condensed consolidated balance sheets when such amounts are with the same counterparty.  In addition, we have recorded accounts payable and receivable balances related to our settled derivatives that are subject to our master netting agreements.  These amounts are not included in the above table; however, under our master netting agreements, we have the right to offset these positions against our forward exposure related to outstanding derivatives.  Should our credit facility become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable.  We could also be required to post cash collateral related to these derivatives under certain circumstances.  As of March 31, 2016 and December 31, 2015, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.

v3.4.0.3

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2016
FAIR VALUE MEASUREMENTS [Abstract]
FAIR VALUE MEASUREMENTS	NOTE 5. FAIR VALUE MEASUREMENTS    The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value.  Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities.  Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.  Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value.  Recurring Basis  The following table presents the fair value hierarchy for our assets and liabilities that are required to be measured at fair value on a recurring basis:                                                               Fair Value Measurements at the End of the Reporting Period            Quoted                        Prices in                        Active                        Markets     Significant                  for     Other     Significant            Identical     Observable     Unobservable            Assets     Inputs     Inputs      Fair Value     (Level 1)     (Level 2)     (Level 3) As of March 31, 2016:                         Assets - Oil, natural gas and natural gas                         liquids derivatives   $ 63,530    $  -   $ 63,530    $  -                          Liabilities:                         Oil, natural gas and natural gas                         liquids derivatives   $ 298    $                –   $ 298    $                – Interest rate swaps     1,820      –     1,820      –    $ 2,118    $               –   $ 2,118    $               –                          As of December 31, 2015:                         Assets:                         Oil, natural gas and natural gas                         liquids derivatives   $ 70,356    $  -   $ 70,356    $  - Interest rate swaps     1,047       -     1,047       -    $ 71,403    $  -   $ 71,403    $  -                           Our derivatives consist of over–the–counter contracts which are not traded on a public exchange.  As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2.  We value these derivatives using the income approach with inputs such as the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data, such as forward LIBOR curves.  Our estimates of fair value have been determined at discrete points in time based on relevant market data.  There were no changes in valuation techniques or related inputs in the three months ended March 31, 2016.     Nonrecurring Basis  In the three months ended March 31, 2015, as a result of a reduction in estimated future net cash flows primarily caused by the continuing decrease in prices, we recognized a $58.2 million impairment charge to write down oil and natural gas properties to their fair value of $31.4 million.   The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from proved reserves.  Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data.    Financial Instruments    The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information.  Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt.  The carrying amounts of our financial instruments other than derivatives and long–term debt approximate fair value because of the short–term nature of the items.  Derivatives are recorded at fair value (see above).          The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us.  The estimated fair value of our senior notes due 2019 was $110.8 million and $211.9 million at March 31, 2016 and December 31, 2015, respectively, which differs from the carrying value of $423.8 million and $423.6 million at March 31, 2016 and December 31, 2015, respectively.  The fair value of the senior notes due 2019 was determined using Level 2 inputs.

v3.4.0.3

ASSET RETIREMENT OBLIGATIONS	3 Months Ended
	Mar. 31, 2016
ASSET RETIREMENT OBLIGATIONS [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 6. ASSET RETIREMENT OBLIGATIONS    We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells.  After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.  The changes in the aggregate ARO are as follows:                                  2016   2015 Balance as of January 1   $ 176,933    $ 105,773  Liabilities incurred     285      288  Revisions     82      (1) Accretion expense     1,988      1,201  Settlements and divestitures     (1,384)     (120) Balance as of March 31   $ 177,904    $ 107,141    As of both March 31, 2016 and December 31, 2015, $2.9 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

v3.4.0.3

LONG-TERM DEBT	3 Months Ended
	Mar. 31, 2016
LONG-TERM DEBT [Abstract]
LONG-TERM DEBT	NOTE 7. LONG–TERM DEBT    Long–term debt, net consisted of the following:                                March 31,   December 31,    2016   2015              Credit facility   $ 242,000    $ 265,000  8.0% senior notes due 2019:               Principal outstanding     426,022      426,022    Unamortized discount and debt issuance costs (1)     (4,755)     (5,116)   Unaccreted premium (2)     2,525      2,708       423,792      423,614  Total   $ 665,792    $ 688,614  _____________ (1)Imputed interest rate of 8.47% and 8.87% for March 31, 2016 and December 31, 2015, respectively.  (2)Imputed interest rate of 7.49% and 7.35% for March 31, 2016 and December 31, 2015, respectively.  Credit Facility    As of March 31, 2016, we have a $1.0 billion credit facility that expires in February 2020.  Borrowings under the facility are secured by a first priority lien on substantially all of our oil and natural gas properties.  We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners.  We also may use up to $100.0 million of available borrowing capacity for letters of credit.  As of March 31, 2016, we have a $0.4 million letter of credit outstanding.  The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense (“EBITDAX”) of no greater than 3.0 to 1.0.  As of March 31, 2016, we were in compliance with these financial covenants.   The facility does not require any repayments of amounts outstanding until it expires in February 2020.  Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.38% and 2.94% at March 31, 2016 and 2015, respectively).      Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves.  As of March 31, 2016, the borrowing base under the facility was $625.0 million.  The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.    In April 2016, we entered into an amendment to the credit facility that, among other things:  · decreased the borrowing base to $450.0 million;  · changed the senior secured funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, 3.0 to 1.0, (b) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0;  · changed the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2018, 5.50 to 1.0, (b) for the fiscal quarters ending June 30, 2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December 31, 2018 and thereafter, 4.25 to 1.0;  · added a cash interest expense to EBITDAX ratio covenant to be no less than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016, 2.5 to 1.0, (b) for the fiscal quarters ending and December 31, 2016, March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and thereafter, 1.5 to 1.0;  · allowed for up to $35.0 million of cash, reduced by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due 2019; and  · limited cash held by us to the greater of 5% of the current borrowing base or $30.0 million.  Should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our short–term liquidity.     8.0% Senior Notes due 2019    Our senior notes due 2019 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes.  Neither EV Energy Partners, L.P. nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.

v3.4.0.3

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2016
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 8. COMMITMENTS AND CONTINGENCIES  We are involved in disputes or legal actions arising in the ordinary course of business.  We do not believe the outcome of such disputes or legal actions will have a material effect on our unaudited condensed consolidated financial statements and no amounts have been accrued at March 31, 2016 or December 31, 2015. 

v3.4.0.3

OWNERS' EQUITY	3 Months Ended
	Mar. 31, 2016
OWNERS' EQUITY [Abstract]
OWNERS' EQUITY	NOTE 9. OWNERS’ EQUITY    Units Outstanding    At March 31, 2016, owners’ equity consists of 49,055,214 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.    Issuance of Units    In the three months ended March 31, 2016, we issued 0.2 million common units related to the vesting of equity–based awards.    Cash Distributions    On January 25, 2016, the board of directors of EV Management declared a $0.075 per unit distribution for the fourth quarter of 2015 on all outstanding units.  The distribution of $3.9 million was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016.    In April 2016, the board of directors of EV Management announced that it had elected to suspend distributions to unitholders.

v3.4.0.3

DISCONTINUTED OPERATIONS	3 Months Ended
	Mar. 31, 2016
DISCONTINUED OPERATIONS [Abstract]
DISCONTINUTED OPERATIONS	NOTE 10. DISCONTINUED OPERATIONS  In 2015, we reclassified our unaudited condensed consolidated financial statements to reflect the operations of our midstream segment as discontinued operations due to the sales of our interest in Cardinal Gas Services, LLC in October 2014 and our interest in Utica East Ohio Midstream LLC in June 2015.   Summarized financial information for our midstream segment is as follows:                     Three Months Ended    March 31,    2015        Revenues   $ 48,543  Operating income     24,474  Net income     24,744  

v3.4.0.3

EARNINGS PER LIMITED PARTNER UNIT	3 Months Ended
	Mar. 31, 2016
EARNINGS PER LIMITED PARTNER UNIT [Abstract]
EARNINGS PER LIMITED PARTNER UNIT	NOTE 11. EARNINGS PER LIMITED PARTNER UNIT    The following sets forth the calculation of earnings per limited partner unit:                    Three Months Ended    March 31,    2016   2015 Loss from continuing operations   $ (29,000)   $ (66,737) General partner's 2% interest in loss from continuing operations     580      1,334  Earnings attributable to unvested phantom units      -     (342) Limited partners' interest in loss from continuing operations   $ (28,420)   $ (65,745)              Earnings per limited partner unit (basic and diluted)   $ (0.58)   $ (1.35)              Income from discontinued operations   $  -   $ 5,070  General partner's 2% interest in income from discontinued operations      -     (101) Limited partners' interest in income from discontinued operations   $  -   $ 4,969               Earnings per limited partner unit (basic and diluted)   $  -   $ 0.10               Net loss   $ (29,000)   $ (61,667) General partner’s 2% interest in net loss     580      1,233  Earnings attributable to unvested phantom units      -     (342) Limited partners’ interest in net loss   $ (28,420)   $ (60,776)              Earnings per limited partner unit (basic and diluted)   $ (0.58)   $ (1.25)              Weighted average limited partner units outstanding (basic and diluted)     49,027      48,795  

v3.4.0.3

RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2016
RELATED PARTY TRANSACTIONS [Abstract]
RELATED PARTY TRANSACTIONS	NOTE 12. RELATED PARTY TRANSACTIONS    Pursuant to an omnibus agreement, we paid EnerVest $4.0 million and $3.3 million in the three months ended March 31, 2016 and 2015, respectively, in monthly administrative fees for providing us general and administrative services.  These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.  These fees are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.      We have entered into operating agreements with EnerVest whereby a wholly owned subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest.  We reimbursed EnerVest approximately $6.1 million and $4.1 million in the three months ended March 31, 2016 and 2015, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties.  As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of the costs that would have been incurred on a standalone basis.  These costs are included in lease operating expenses in our unaudited condensed consolidated statements of operations.  Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

v3.4.0.3

OTHER SUPPLEMENTAL INFORMATION	3 Months Ended
	Mar. 31, 2016
OTHER SUPPLEMENTAL INFORMATION [Abstract]
OTHER SUPPLEMENTAL INFORMATION	NOTE 13. OTHER SUPPLEMENTAL INFORMATION      Supplemental cash flows and noncash transactions were as follows:                                 Three Months Ended    March 31,    2016   2015 Supplemental cash flows information:                          Cash paid for interest   $ 1,557    $ 3,303  Cash paid for income taxes     11,318       -                                  As of March 31,    2016   2015                             Noncash transaction - costs for additions to oil and natural gas properties in             accounts payable and accrued liabilities   $ 5,420    $ 15,964   Accounts payable and accrued liabilities consisted of the following:                                March 31,   December 31,    2016   2015 Costs for additions to oil and natural gas properties   $ 5,420    $ 5,212  Lease operating expenses     9,293      10,576  Interest     15,786      7,298  Production and ad valorem taxes     5,129      6,763  VPP     3,016      3,984  General and administrative expenses     1,909      2,864  Current portion of ARO     2,930      2,930  Other     1,635      3,508  Total   $ 45,118    $ 43,135  

v3.4.0.3

NEW ACCOUNTING STANDARDS	3 Months Ended
	Mar. 31, 2016
NEW ACCOUNTING STANDARDS [Abstract]
NEW ACCOUNTING STANDARDS	NOTE 14. NEW ACCOUNTING STANDARDS     In August 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)  No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter.  We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.  In March 2016, the FASB issued ASU No. 2016–09, Compensation – Stock Compensation.  This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows.  The provisions of ASU 2016–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods.  Early adoption is permitted for financial statements that have not yet been previously issued.  We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.  No other new accounting pronouncements issued or effective during the three months ended March 31, 2016 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

v3.4.0.3

ORGANIZATION AND NATURE OF BUSINESS (Policy)	3 Months Ended
	Mar. 31, 2016
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
Nature of Operations	Nature of Operations    EV Energy Partners, L.P. together with its wholly owned subsidiaries (“we,” “our” or “us”) is a publicly held limited partnership.  Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company.  EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership.  EnerVest and its affiliates also have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights.
Basis of Presentation	Basis of Presentation    Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”).  Accordingly, certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted.  We believe that the presentations and disclosures herein are adequate to make the information not misleading.  The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods.  The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year.  These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2015.    All intercompany accounts and transactions have been eliminated in consolidation.  In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated. 

v3.4.0.3

ACQUISITIONS (Tables)	3 Months Ended
	Mar. 31, 2016
ACQUISITIONS [Abstract]
Pro Forma Revenues, Net Income And Net Income Per Limited Partner Unit	                 Three Months    Ended    March 31,    2015 Revenues:       Historical   $ 47,242  Belden     8,112  Austin Chalk     3,212  Appalachian and San Juan Basins     7,965  Pro forma revenues   $ 66,531         Net income (loss):       Historical   $ (61,667) Belden     (623) Austin Chalk     573  Appalachian and San Juan Basins     (42) Pro forma net loss   $ (61,759) 

v3.4.0.3

RISK MANAGEMENT (Tables)	3 Months Ended
	Mar. 31, 2016
RISK MANAGEMENT [Abstract]
Commodity Contracts	As of March 31, 2016, we had entered into commodity contracts with the following terms:                              Period Covered   Hedged Volume   Weighted Average Fixed Price Oil (MBbls):           Swaps – April 2016   30.0    $ 90.14  Swaps – May 2016 to September 2016   459.0      57.68  Swaps – October 2016 to December 2016   92.0      90.14             Natural Gas (MmmBtus):           Swaps – April 2016 to December 2016   29,975.0      3.57  Swaps – 2017   32,850.0      3.07             Natural Gas Liquids (MBbls):           Swap – April 2016 to December 2016   2.8      9.14             
Interest Rate Swaps	As of March 31, 2016, we had entered into interest rate swaps with the following terms:                                   Period Covered   Notional Amount   Floating Rate   Fixed Rate January 2017 – December 2017   $ 100,000    1 Month LIBOR   1.039%  January 2018 – September 2020     100,000    1 Month LIBOR   1.795%  
Fair Value of Derivatives	The following table sets forth the fair values and classification of our outstanding derivatives:                                                           Net Amounts            Gross Amounts     of Assets            Offset in the     Presented in the      Gross     Unaudited     Unaudited      Amounts of     Condensed     Condensed      Recognized     Consolidated     Consolidated      Assets     Balance Sheet     Balance Sheet Derivatives:                   As of March 31, 2016:                   Derivative asset   $ 55,434    $ (298)   $ 55,136  Long–term derivative asset     8,096       -     8,096  Total   $ 63,530    $ (298)   $ 63,232                     As of December 31, 2015:                   Derivative asset   $ 60,662    $  -   $ 60,662  Long–term derivative asset     10,741       -     10,741  Total   $ 71,403    $  -   $ 71,403                                                           Net Amounts            Gross Amounts     of Liabilities            Offset in the     Presented in the      Gross     Unaudited     Unaudited      Amounts of     Condensed     Condensed      Recognized     Consolidated     Consolidated      Liabilities     Balance Sheet     Balance Sheet Derivatives:                   As of March 31, 2016:                   Derivative liability   $ 298    $ (298)   $  - Long–term derivative liability     1,820       -     1,820  Total   $ 2,118    $ (298)   $ 1,820  

v3.4.0.3

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2016
FAIR VALUE MEASUREMENTS [Abstract]
Fair Value Hierarchy for Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the fair value hierarchy for our assets and liabilities that are required to be measured at fair value on a recurring basis:                                                               Fair Value Measurements at the End of the Reporting Period            Quoted                        Prices in                        Active                        Markets     Significant                  for     Other     Significant            Identical     Observable     Unobservable            Assets     Inputs     Inputs      Fair Value     (Level 1)     (Level 2)     (Level 3) As of March 31, 2016:                         Assets - Oil, natural gas and natural gas                         liquids derivatives   $ 63,530    $  -   $ 63,530    $  -                          Liabilities:                         Oil, natural gas and natural gas                         liquids derivatives   $ 298    $                –   $ 298    $                – Interest rate swaps     1,820      –     1,820      –    $ 2,118    $               –   $ 2,118    $               –                          As of December 31, 2015:                         Assets:                         Oil, natural gas and natural gas                         liquids derivatives   $ 70,356    $  -   $ 70,356    $  - Interest rate swaps     1,047       -     1,047       -    $ 71,403    $  -   $ 71,403    $  -                          

v3.4.0.3

ASSET RETIREMENT OBLIGATIONS (Tables)	3 Months Ended
	Mar. 31, 2016
ASSET RETIREMENT OBLIGATIONS [Abstract]
Changes in Aggregate Asset Retirement Obligation	The changes in the aggregate ARO are as follows:                                  2016   2015 Balance as of January 1   $ 176,933    $ 105,773  Liabilities incurred     285      288  Revisions     82      (1) Accretion expense     1,988      1,201  Settlements and divestitures     (1,384)     (120) Balance as of March 31   $ 177,904    $ 107,141  

v3.4.0.3

LONG-TERM DEBT (Tables)	3 Months Ended
	Mar. 31, 2016
LONG-TERM DEBT [Abstract]
Long Term Debt	Long–term debt, net consisted of the following:                                March 31,   December 31,    2016   2015              Credit facility   $ 242,000    $ 265,000  8.0% senior notes due 2019:               Principal outstanding     426,022      426,022    Unamortized discount and debt issuance costs (1)     (4,755)     (5,116)   Unaccreted premium (2)     2,525      2,708       423,792      423,614  Total   $ 665,792    $ 688,614  _____________ (1)Imputed interest rate of 8.47% and 8.87% for March 31, 2016 and December 31, 2015, respectively.  (2)Imputed interest rate of 7.49% and 7.35% for March 31, 2016 and December 31, 2015, respectively.

v3.4.0.3

DISCONTINUED OPERATIONS (Tables)	3 Months Ended
	Mar. 31, 2016
DISCONTINUED OPERATIONS [Abstract]
Discontinued Operation Financial Information	Summarized financial information for our midstream segment is as follows:                     Three Months Ended    March 31,    2015        Revenues   $ 48,543  Operating income     24,474  Net income     24,744  

v3.4.0.3

EARNINGS PER LIMITED PARTNER UNIT (Tables)	3 Months Ended
	Mar. 31, 2016
EARNINGS PER LIMITED PARTNER UNIT [Abstract]
Calculation of Earnings Per Limited Partner Unit	The following sets forth the calculation of earnings per limited partner unit:                    Three Months Ended    March 31,    2016   2015 Loss from continuing operations   $ (29,000)   $ (66,737) General partner's 2% interest in loss from continuing operations     580      1,334  Earnings attributable to unvested phantom units      -     (342) Limited partners' interest in loss from continuing operations   $ (28,420)   $ (65,745)              Earnings per limited partner unit (basic and diluted)   $ (0.58)   $ (1.35)              Income from discontinued operations   $  -   $ 5,070  General partner's 2% interest in income from discontinued operations      -     (101) Limited partners' interest in income from discontinued operations   $  -   $ 4,969               Earnings per limited partner unit (basic and diluted)   $  -   $ 0.10               Net loss   $ (29,000)   $ (61,667) General partner’s 2% interest in net loss     580      1,233  Earnings attributable to unvested phantom units      -     (342) Limited partners’ interest in net loss   $ (28,420)   $ (60,776)              Earnings per limited partner unit (basic and diluted)   $ (0.58)   $ (1.25)              Weighted average limited partner units outstanding (basic and diluted)     49,027      48,795  

v3.4.0.3

OTHER SUPPLEMENTAL INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2016
OTHER SUPPLEMENTAL INFORMATION [Abstract]
Supplemental Cash Flows and Non-Cash Transactions	Supplemental cash flows and noncash transactions were as follows:                                 Three Months Ended    March 31,    2016   2015 Supplemental cash flows information:                          Cash paid for interest   $ 1,557    $ 3,303  Cash paid for income taxes     11,318       -                                  As of March 31,    2016   2015                             Noncash transaction - costs for additions to oil and natural gas properties in             accounts payable and accrued liabilities   $ 5,420    $ 15,964  
Schedule of Accounts Payable and Accrued Liabilities- Third Party	Accounts payable and accrued liabilities consisted of the following:                                March 31,   December 31,    2016   2015 Costs for additions to oil and natural gas properties   $ 5,420    $ 5,212  Lease operating expenses     9,293      10,576  Interest     15,786      7,298  Production and ad valorem taxes     5,129      6,763  VPP     3,016      3,984  General and administrative expenses     1,909      2,864  Current portion of ARO     2,930      2,930  Other     1,635      3,508  Total   $ 45,118    $ 43,135  

v3.4.0.3

ORGANIZATION AND NATURE OF BUSINESS (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Apr. 30, 2016
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage of general partnership interest	2.00%
EnerVest, Ltd.
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage of ownership interest in EV Energy GP, L.P. (EV Energy GP)	71.25%
8.0% Senior Notes due 2019 [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Senior notes, maturity year	2019
Senior unsecured notes, stated interest rate	8.00%
8.0% Senior Notes due 2019 [Member] | Subsequent Event [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Debt instrument, repurchased face amount		$ 72.9
Debt instrument, repurchase amount		$ 30.1

v3.4.0.3

EQUITY-BASED COMPENSATION (Details) - USD ($) $ in Thousands, shares in Millions	1 Months Ended	3 Months Ended
	Sep. 30, 2011	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation cost		$ 1,600	$ 4,952
Unvested Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		4 years
Equity-based compensation cost		$ 1,600	4,700
Unrecognized compensation expense		$ 12,800
Weighted average period		2 years 4 months 24 days
Performance units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation cost			$ 200
Shares issued	0.3

v3.4.0.3

ACQUISITIONS (Narrative) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016 USD ($) MMcf	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($) MMcf	Oct. 31, 2015 USD ($) MMcf
Business Acquisition [Line Items]
Oil, natural gas and natural gas liquids revenues	$ 37,739	$ 46,425
Volume obligation to deliver, billion cubic feet (Bcf) of natural gas | MMcf				2,400,000
Volume obligation to deliver, remaining, (Bcf) of natrual gas | MMcf	1,400		1,900
Liability related to volumetric production payment (VPP)	$ 3,016		$ 3,984
Accretion expense	$ 100
Belden [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price				$ 111,100
Austin Chalk [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price				25,900
Appalachian Basin and San Juan Basin [Member]
Business Acquisition [Line Items]
Oil and natural gas properties acquired, purchase price				$ 122,000

v3.4.0.3

ACQUISITIONS (Pro Forma Revenues, Net Income and Net Income Per Limited Partner Unit) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2015 USD ($)
Business Acquisition [Line Items]
Revenues	$ 66,531
Net income (loss)	(61,759)
Historical [Member]
Business Acquisition [Line Items]
Revenues	47,242
Net income (loss)	(61,667)
Belden [Member]
Business Acquisition [Line Items]
Revenues	8,112
Net income (loss)	(623)
Austin Chalk [Member]
Business Acquisition [Line Items]
Revenues	3,212
Net income (loss)	573
Appalachian Basin and San Juan Basin [Member]
Business Acquisition [Line Items]
Revenues	7,965
Net income (loss)	$ (42)

v3.4.0.3

RISK MANAGEMENT (Commodity Contracts) (Details)	Mar. 31, 2016 MMBTU $ / MMBTU $ / MBbls MMBbls
Oil [Member] | Swaps April 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MBbls) | MMBbls	30.0
Weighted Average Fixed Price | $ / MBbls	90.14
Oil [Member] | Swaps - May 2016 to September 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MBbls) | MMBbls	459.0
Weighted Average Fixed Price | $ / MBbls	57.68
Oil [Member] | Swaps - October 2016 to December 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MBbls) | MMBbls	92.0
Weighted Average Fixed Price | $ / MBbls	90.14
Natural Gas [Member] | Swaps - April 2016 to December 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MmmBtus) | MMBTU	29,975.0
Weighted Average Fixed Price | $ / MMBTU	3.57
Natural Gas [Member] | Swaps - 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MmmBtus) | MMBTU	32,850.0
Weighted Average Fixed Price | $ / MMBTU	3.07
Natural Gas Liquids [Member] | Swaps - April 2016 to December 2016 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Hedged Volume (MBbls) | MMBbls	2.8
Weighted Average Fixed Price | $ / MBbls	9.14

v3.4.0.3

RISK MANAGEMENT (Interest Rate Swaps) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016 USD ($)
Interest Rate Swap January 2017 - December 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional amount	$ 100,000
Floating rate	1 Month LIBOR
Fixed rate	1.039%
Interest Rate Swap January 2018 - September 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional amount	$ 100,000
Floating rate	1 Month LIBOR
Fixed rate	1.795%

v3.4.0.3

RISK MANAGEMENT (Fair Value of Derivatives) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Derivative Assets [Abstract]
Derivative asset, fair value	$ 63,530	$ 71,403
Derivative asset, liability	(298)
Derivative asset	55,136	60,662
Long-term derivative asset	8,096	10,741
Net recorded fair value	63,232	71,403
Derivative Liabilities [Abstract]
Derivative liability, fair value	2,118
Derivative liability, asset	(298)
Long-term derivative liability	1,820
Net recorded fair value	1,820
Current Assets [Member]
Derivative Assets [Abstract]
Derivative asset, fair value	55,434	60,662
Derivative asset, liability	(298)
Derivative asset	55,136	60,662
Long-term Derivative Asset [Member]
Derivative Assets [Abstract]
Derivative asset, fair value	8,096	10,741
Long-term derivative asset	8,096	10,741
Derivative Liability [Member]
Derivative Liabilities [Abstract]
Derivative liability, fair value	298
Derivative liability, asset	(298)
Long-term Derivative Liability [Member]
Derivative Liabilities [Abstract]
Derivative liability, fair value	1,820
Long-term derivative liability	1,820
Commodity contracts [Member]
Derivative Assets [Abstract]
Derivative asset, fair value	63,530	70,356
Derivative Liabilities [Abstract]
Derivative liability, fair value	298
Interest rate swaps [Member]
Derivative Assets [Abstract]
Derivative asset, fair value		$ 1,047
Derivative Liabilities [Abstract]
Derivative liability, fair value	$ 1,820

v3.4.0.3

FAIR VALUE MEASUREMENTS (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Fair Value Measurements [Line Items]
Impairment of oil and gas properties	$ 687	$ 58,173
Oil and natural gas properties, fair value		$ 31,400
Long-term Debt	$ 665,792		$ 688,614
8.0% Senior Notes due 2019 [Member]
Fair Value Measurements [Line Items]
Senior notes, maturity year	2019
Senior notes, fair value	$ 110,800		211,900
Long-term Debt	$ 423,792		$ 423,614

v3.4.0.3

FAIR VALUE MEASUREMENTS (Fair Value Hierarchy for Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative asset, fair value	$ 63,530	$ 71,403
Derivative liability, fair value	2,118
Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative asset, fair value	63,530	70,356
Derivative liability, fair value	298
Interest rate swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative asset, fair value		1,047
Derivative liability, fair value	1,820
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative asset, fair value		71,403
Derivative liability, fair value	2,118
Significant Other Observable Inputs (Level 2) | Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative asset, fair value	63,530	70,356
Derivative liability, fair value	298
Significant Other Observable Inputs (Level 2) | Interest rate swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative asset, fair value		$ 1,047
Derivative liability, fair value	$ 1,820

v3.4.0.3

ASSET RETIREMENT OBLIGATIONS (Narrative) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
ASSET RETIREMENT OBLIGATIONS [Abstract]
Asset retirement obligation, current	$ 2,930	$ 2,930

v3.4.0.3

ASSET RETIREMENT OBLIGATIONS (Changes in Aggregate Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
ASSET RETIREMENT OBLIGATIONS [Abstract]
Balance at beginning of period	$ 176,933	$ 105,773
Liabilities incurred	285	288
Revisions	82	(1)
Accretion expense	1,988	1,201
Settlements and divestitures	(1,384)	(120)
Balance at end of period	$ 177,904	$ 107,141

v3.4.0.3

LONG-TERM DEBT (Narrative) (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Apr. 30, 2016 USD ($)	Mar. 31, 2016 USD ($) item	Mar. 31, 2015	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2015 USD ($)
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity		$ 1,000,000
Senior secured credit facility, expiration date		2020-02
Minimum current ratio required under credit facility | item		1.0
Maximum total debt to earnings ratio required under credit facility | item		3.0
Weighted average effective interest rate		3.38%	2.94%
Line of credit, borrowing base		$ 625,000
Line of credit, borrowing base redetermination period		The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.
Line of credit facility amount outstanding		$ 242,000													$ 265,000
Secured funds to EBITDAX ratio		3.00%
Cash interest expense to EBITDAX ratio		2.50%
Subsequent Event [Member]
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity	$ 450,000
Percentage of cash, per current borrowing base	5.00%
Amount of cash, equivalent to percentage	$ 30,000
Subsequent Event [Member] | Scenario, Plan [Member]
Debt Instrument [Line Items]
Secured funds to EBITDAX ratio								4.00%	4.00%	3.50%	3.50%	3.00%	3.00%	3.00%
Aggregate debt to EBITDAX ratio				4.25%	5.25%	5.25%	5.50%
Cash interest expense to EBITDAX ratio									1.50%	2.00%	2.00%	2.00%	2.50%	2.50%
8.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Senior unsecured notes, stated interest rate		8.00%
Senior notes, maturity year		2019
8.0% Senior Notes due 2019 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Cash amount available per credit facility amendement for redemption	$ 35,000
Borrowing Base Determination, Period One [Member]
Debt Instrument [Line Items]
Borrowing base scheduled redetermination date		--04-01
Borrowing Base Determination, Period Two [Member]
Debt Instrument [Line Items]
Borrowing base scheduled redetermination date		--10-01
Letter of Credit [Member]
Debt Instrument [Line Items]
Senior secured credit facility, maximum borrowing capacity		$ 100,000
Line of credit facility amount outstanding		$ 400

v3.4.0.3

LONG-TERM DEBT (Long Term Debt) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Credit facility outstanding	$ 242,000	$ 265,000
Long-term debt, Total	665,792	688,614
8.0% Senior Notes due 2019 [Member]
Senior notes, outstanding	426,022	426,022
Unamortized discount and debt issuance costs	(4,755)	(5,116)
Unaccreted premium	2,525	2,708
Long-term debt, Total	$ 423,792	$ 423,614
Debt instrument, unamortized discount, imputed interest	8.47%	8.87%
Debt instrument, unaccreted expense, imputed interest	7.49%	7.35%

v3.4.0.3

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
COMMITMENTS AND CONTINGENCIES [Abstract]
Loss contingency accrual	$ 0.0	$ 0.0

v3.4.0.3

OWNERS' EQUITY (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands			3 Months Ended
	Feb. 12, 2016	Jan. 25, 2016	Mar. 31, 2016	Mar. 31, 2015
Stockholders Equity Note [Line Items]
Percentage of limited partnership interest			98.00%
Percentage of general partnership interest			2.00%
Units vested			200,000
Contribution from general partner				$ 91
Distributions paid			$ 3,868	$ 25,274
Distribution to unitholders declared per unit		$ 0.075		$ 0.50
Distribution to unitholders, amount declared	$ 3,900
Distribution to unitholders, record date	Feb. 05, 2016
Distribution to unitholders, payment date	Feb. 12, 2016
Common Unitholders [Member]
Stockholders Equity Note [Line Items]
Common units outstanding			49,055,214
Distributions paid			$ 3,793	$ 24,777
General Partner Interest [Member]
Stockholders Equity Note [Line Items]
Contribution from general partner				91
Distributions paid			$ 75	$ 497

v3.4.0.3

DISCONTINUED OPERATIONS (Summarized Financial Information Discontinued Operations) (Details) - Utica East Ohio Midstream LLC and Cardinal Gas Services LLC [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2015 USD ($)
Schedule Of Equity Method Investments [Line Items]
Revenues	$ 48,543
Operating income	24,474
Net income	$ 24,744

v3.4.0.3

EARNINGS PER LIMITED PARTNER UNIT (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
EARNINGS PER LIMITED PARTNER UNIT [Abstract]
Loss from continuing operations	$ (29,000)	$ (66,737)
General partner's 2% interest in loss from continuing operations	580	1,334
Earnings attributable to unvested phantom units, continuing operations		(342)
Limited partners' interest in loss from continuing operations	$ (28,420)	$ (65,745)
Loss per limited partner unit (basic and diluted), continuing	$ (0.58)	$ (1.35)
Income from discontinued operations		$ 5,070
General partner's 2% interest in income from discontinued operations		(101)
Limited partners' interest in income from discontinued operations		$ 4,969
Earnings per limited partner unit (basic and diluted), discontinued		$ 0.10
Net loss	$ (29,000)	$ (61,667)
General partner's 2% interest in net loss	580	1,233
Earnings attributable to unvested phantom units		(342)
Limited partners' interest in net loss	$ (28,420)	$ (60,776)
Earnings per share, basic and diluted	$ (0.58)	$ (1.25)
Weighted average limited partner units outstanding - basic and diluted	49,027	48,795
Percentage of general partnership interest	2.00%

v3.4.0.3

RELATED PARTY TRANSACTIONS (Details) - EnerVest, Ltd. - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Related Party Transaction [Line Items]
Administrative fees paid to related party	$ 4.0	$ 3.3
Direct expenses incurred and reimbursed to related party	$ 6.1	$ 4.1

v3.4.0.3

OTHER SUPPLEMENTAL INFORMATION (Supplemental Cash Flows and Non-Cash Transactions) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Supplemental cash flows information:
Cash paid for interest	$ 1,557	$ 3,303
Cash paid for income taxes	11,318
Non-cash transactions:
Noncash transaction - costs for additions to oil and natural gas properties in accounts payable and accrued liabilities	$ 5,420	$ 15,964

v3.4.0.3

OTHER SUPPLEMENTAL INFORMATION (Schedule of Accounts Payable and Accrued Liabilities- Third Party) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Other Supplemental Information Disclosure [Abstract]
Costs for additions to oil and natural gas properties	$ 5,420	$ 5,212
Lease operating expenses	9,293	10,576
Interest	15,786	7,298
Production and ad valorem taxes	5,129	6,763
VPP	3,016	3,984
General and administrative expenses	1,909	2,864
Current portion of ARO	2,930	2,930
Other	1,635	3,508
Total	$ 45,118	$ 43,135

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