EV Energy Partners, LP (Form: 10-Q, Received: 08/09/2013 06:13:11)

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 June 30, 2013

¨ 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 August 5, 2013, the registrant had 42,599,080 common units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements (Unaudited)	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22
Item 4.	Controls and Procedures	23

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	23
Item 1A.	Risk Factors	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	23
Item 3.	Defaults Upon Senior Securities	23
Item 4.	Mine Safety Disclosures	23
Item 5.	Other Information	24
Item 6.	Exhibits	25

Signatures		26

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EV Energy Partners, L.P.

Condensed Consolidated Balance Sheets

(In thousands, except number of units)

(Unaudited)

	June 30,			December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	8,277		$	7,486
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		37,927			34,909
Related party		5,002			1,422
Other		1,740			11,263
Derivative asset		31,251			40,771
Other current assets		4,051			1,750
Total current assets		88,248			97,601

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; June 30, 2013, $447,641; December 31, 2012, $389,206		1,862,710			1,875,890
Other property, net of accumulated depreciation and amortization; June 30, 2013, $675; December 31, 2012, $598		1,295			1,325
Long–term derivative asset		46,204			45,839
Investments in unconsolidated affiliates		153,187			34,545
Other assets		9,048			10,214
Total assets	$	2,160,692		$	2,065,414

LIABILITIES AND OWNERS’ EQUITY

Current liabilities – Accounts payable and accrued liabilities	$	44,814		$	40,171

Asset retirement obligations		105,266			102,707
Long–term debt		1,019,256			859,218
Other long–term liabilities		1,680			3,494

Commitments and contingencies

Owners’ equity:
Common unitholders – 42,599,080 units and 42,320,707 units issued and outstanding as of June 30, 2013 and December 31, 2012, respectively		1,003,131			1,072,175
General partner interest		(13,455	)		(12,351	)
Total owners’ equity		989,676			1,059,824
Total liabilities and owners’ equity	$	2,160,692		$	2,065,414

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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues:
Oil, natural gas and natural gas liquids revenues	$	80,332		$	62,793		$	153,001		$	139,594
Transportation and marketing–related revenues		1,270			759			2,303			1,689
Total revenues		81,602			63,552			155,304			141,283

Operating costs and expenses:
Lease operating expenses		26,217			24,850			52,311			53,450
Cost of purchased natural gas		951			501			1,694			1,146
Dry hole and exploration costs		902			1,682			1,319			3,855
Production taxes		2,924			2,525			5,840			5,807
Asset retirement obligations accretion expense		1,205			1,220			2,559			2,428
Depreciation, depletion and amortization		27,670			28,395			58,503			52,986
General and administrative expenses		9,121			10,149			21,743			22,266
Impairment of oil and natural gas properties		2,829			16,264			7,998			16,899
Total operating costs and expenses		71,819			85,586			151,967			158,837

Operating income (loss)		9,783			(22,034	)		3,337			(17,554	)

Other income (expense), net:
Realized gains on derivatives, net		4,461			34,603			15,220			58,793
Unrealized gains (losses) on derivatives, net		30,286			15,537			(7,987	)		27,198
Interest expense		(11,604	)		(12,595	)		(24,433	)		(23,679	)
Other income (expense), net		55			(30	)		242			(26	)
Total other income (expense), net		23,198			37,515			(16,958	)		62,286

Income (loss) before income taxes and equity in income (losses) of unconsolidated affiliates		32,981			15,481			(13,621	)		44,732

Income taxes		(216	)		(439	)		(393	)		(1,097	)

Income (loss) before equity in income (losses) of unconsolidated affiliates		32,765			15,042			(14,014	)		43,635

Equity in income (losses) of unconsolidated affiliates		89			(86	)		287			(86	)

Net income (loss)	$	32,854		$	14,956		$	(13,727	)	$	43,549

Net income (loss) per limited partner unit:
Basic	$	0.74		$	0.35		$	(0.34	)	$	1.03
Diluted	$	0.74		$	0.34		$	(0.34	)	$	1.02

Weighted average limited partner units outstanding:
Basic		42,599			42,452			42,578			41,446
Diluted		42,659			42,678			42,578			41,739

Distributions declared per unit	$	0.769		$	0.765		$	1.537		$	1.529

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Changes in Owners’ Equity

(In thousands, except number of units)

(Unaudited)

				General			Total
	Common			Partner			Owners’
	Unitholders			Interest			Equity

Balance, December 31, 2012	$	1,072,175		$	(12,351	)	$	1,059,824
Conversion of 40,264 vested phantom units		2,365			–			2,365
Contribution from general partner		–			334			334
Distributions		(66,386	)		(1,335	)		(67,721	)
Equity–based compensation		8,429			172			8,601
Net loss		(13,452	)		(275	)		(13,727	)
Balance, June 30, 2013	$	1,003,131		$	(13,455	)	$	989,676

							General			Total
	Common			Class B			Partner			Owners’
	Unitholders			Unitholders			Interest			Equity

Balance, December 31, 2011	$	935,425		$	232		$	(15,618	)	$	920,039
Conversion of 41,075 vested phantom units		2,836			–			–			2,836
Proceeds from public equity offering, net of offering costs of $304		262,529			–			–			262,529
Contributions from general partner		–			–			5,714			5,714
Distributions		(55,638	)		(5,915	)		(1,256	)		(62,809	)
Equity–based compensation		6,916			–			–			6,916
Net income		38,644			4,034			871			43,549
Balance, June 30, 2012	$	1,190,712		$	(1,649	)	$	(10,289	)	$	1,178,774

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2013			2012

Cash flows from operating activities:
Net (loss) income	$	(13,727	)	$	43,549
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		2,559			2,428
Depreciation, depletion and amortization		58,503			52,986
Equity–based compensation cost		8,783			8,096
Impairment of oil and natural gas properties		7,998			16,899
Noncash derivative activity		9,155			(27,198	)
Equity in (income) losses of unconsolidated affiliates		(287	)		86
Distributions from unconsolidated affiliates		62			–
Other		1,411			3,948
Changes in operating assets and liabilities:
Accounts receivable		(5,044	)		4,225
Other current assets		(2,300	)		365
Accounts payable and accrued liabilities		3,494			9,758
Other, net		(200	)		(2,102	)
Net cash flows provided by operating activities		70,407			113,040

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		–			(35,728	)
Final settlement of purchase price of oil and natural gas properties		7,998			–
Additions to oil and natural gas properties		(51,808	)		(62,566	)
Proceeds from sale of oil and natural gas properties		–			5,489
Investments in unconsolidated affiliates		(118,446	)		(11,947	)
Distributions from unconsolidated affiliates		27			–
Settlements from acquired derivatives		–			3,676
Net cash flows used in investing activities		(162,229	)		(101,076	)

Cash flows from financing activities:
Long–term debt borrowings		160,000			40,000
Repayment of long–term debt borrowings		–			(460,000	)
Proceeds from debt offering		–			206,000
Loan costs incurred		–			(4,078	)
Proceeds from public equity offering		–			262,833
Offering costs		–			(304	)
Contributions from general partner		334			5,714
Distributions paid		(67,721	)		(62,809	)
Net cash flows provided by (used in) financing activities		92,613			(12,644	)

Increase (decrease) in cash and cash equivalents		791			(680	)
Cash and cash equivalents – beginning of period		7,486			30,312
Cash and cash equivalents – end of period	$	8,277		$	29,632

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. (the “Parent”) and its wholly owned subsidiaries (“we,” “our” or “us”) are a publicly held limited partnership that engages in the acquisition, development and production of oil and natural gas properties. 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.

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

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, 2012.

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.

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 primarily of phantom units and performance units.

We accounted for the phantom units issued prior to 2009 as liability awards, and the fair value of these phantom units was remeasured at the end of each reporting period based on the current market price of our common units until settlement. Prior to settlement, compensation cost was recognized for these phantom units based on the proportionate amount of the requisite service period that has been rendered to date. The last of these phantom units vested in January 2013.

We account for the phantom units issued beginning in 2009 as equity awards, and we estimated the fair value of these phantom units using the Black–Scholes option pricing model. We account for the performance units as equity awards, and we estimated the fair value of these market condition performance units using the Monte Carlo simulation model.

The following table presents the compensation costs recognized in our unaudited condensed consolidated statements of operations:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012

Liability awards	$	–	$	357	$	182	$	1,180
Equity awards		4,297		3,459		8,601		6,916
Total	$	4,297	$	3,816	$	8,783	$	8,096

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

As of June 30, 2013, there was $35.3 million of unrecognized compensation costs related to our unvested phantom units and performance units which are expected to be recognized over a weighted average period of 2.5 years.

NOTE 3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

The most significant of our investments in unconsolidated affiliates are Cardinal Gas Services, LLC (“Cardinal”) and Utica East Ohio Midstream LLC (“UEO”). We own 9% of Cardinal and 21% of UEO, which are constructing natural gas processing, natural gas liquids fractionation and connecting pipeline facilities to serve anticipated production in the Utica Shale in Ohio.

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, c hanges in the fair value of our derivatives are recorded immediately to operations as “Unrealized gains (losses) on derivatives, net” in our unaudited condensed consolidated statements of operations.

As of June 30, 2013, we had entered into commodity contracts with the following terms:

Period Covered	Hedged Volume		Weighted Average Fixed Price
Oil (MBbls):
Swaps – July 2013 to December 2013		763.6	$	88.99
Swaps – 2014		1,517.7		91.19
Swaps – 2015		730.0		90.09

Natural Gas (MmmBtus):
Swaps – July 2013 to December 2013		18,639.2		4.93
Swaps – 2014		31,609.0		4.88
Swaps – 2015		31,572.5		5.07

As of June 30, 2013, we had entered into interest rate swaps with the following terms:

	Notional		Floating	Fixed
Period Covered	Amount		Rate	Rate
July 2013 – July 2015	$	110,000	1 Month LIBOR		3.315	%

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 Sheets			Balance Sheets
Derivatives:
As of June 30, 2013:
Derivative asset	$	41,759	$	(10,508	)	$	31,251
Long–term derivative asset		49,710		(3,506	)		46,204
Total	$	91,469	$	(14,014	)	$	77,455

As of December 31, 2012:
Derivative asset	$	44,173	$	(3,402	)	$	40,771
Long–term derivative asset		50,692		(4,853	)		45,839
Total	$	94,865	$	(8,255	)	$	86,610

						Net Amounts
			Gross Amounts			of Liabilities
			Offset in the			Presented in the
	Gross		Unaudited			Unaudited
	Amounts of		Condensed			Condensed
	Recognized		Consolidated			Consolidated
	Liabilities		Balance Sheets			Balance Sheets
Derivatives:
As of June 30, 2013:
Derivative liability	$	10,508	$	(10,508	)	$	–
Long–term derivative liability		3,506		(3,506	)		–
Total	$	14,014	$	(14,014	)	$	–

As of December 31, 2012:
Derivative liability	$	3,402	$	(3,402	)	$	–
Long–term derivative liability		4,853		(4,853	)		–
Total	$	8,255	$	(8,255	)	$	–

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 June 30, 2013 and December 31, 2012, 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)

The following table presents the impact of derivatives and their location within the unaudited condensed consolidated statements of operations:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Realized gains on derivatives, net:
Commodity contracts	$	5,816		$	35,646		$	18,120		$	60,952
Interest rate swaps		(1,355	)		(1,043	)		(2,900	)		(2,159	)
Total	$	4,461		$	34,603		$	15,220		$	58,793

Unrealized gains (losses) on derivatives, net:
Commodity contracts	$	28,644		$	15,308		$	(11,077	)	$	26,462
Interest rate swaps		1,642			229			3,090			736
Total	$	30,286		$	15,537		$	(7,987	)	$	27,198

NOTE 5. FAIR VALUE MEASUREMENTS

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 June 30, 2013:
Assets – Commodity contracts	$	91,469	$	–	$	91,469	$	–

Liabilities:
Commodity contracts	$	7,673	$	–	$	7,673	$	–
Interest rate swaps		6,341		–		6,341		–
Total	$	14,014	$	–	$	14,014	$	–

As of December 31, 2012:
Assets – Commodity contracts	$	94,865	$	–	$	94,865	$	–

Liabilities – Interest rate swaps	$	8,255	$	–	$	8,255	$	–

Our derivatives consist of over–the–counter (“OTC”) 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 based on observable market data for similar instruments. This observable data includes 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 six months ended June 30, 2013.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Nonrecurring Basis

In March 2012, in conjunction with the sale of assets held for sale at December 31, 2011, we incurred $0.4 million of additional impairment charges to write down these assets to their fair value of $6.1 million. The impairment charge was included in earnings for the six months ended June 30, 2012. The fair value was determined using Level 2 inputs consisting of the mutually agreed upon selling price we received upon the sale of these oil and natural gas properties.

In June 2012, oil and natural gas properties with a carrying amount of $29.3 million were written down to their fair value of $13.1 million, resulting in an impairment charge of $16.2 million. The impairment charge was included in earnings for the three and six months ended June 30, 2012. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk–adjusted discount rates and other relevant data.

Leasehold Impairments

We incurred leasehold impairment charges of $2.8 million and $0.1 million in the three months ended June 30, 2013 and 2012, respectively, and $8.0 million and $0.2 million in the six months ended June 30, 2013 and 2012, respectively.

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. As of June 30, 2013 and December 31, 2012, the estimated fair value of our senior notes due 2019 was $498.8 million and $531.2 million, respectively, which differs from the carrying value of $499.3 million and $499.2 million, respectively. T he 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:

	2013			2012
Balance as of January 1	$	104,684		$	93,225
Liabilities incurred		533			655
Accretion expense		2,559			2,428
Revisions in estimated cash flows		–			1,056
Settlements and divestitures		(533	)		(252	)
Balance as of June 30	$	107,243		$	97,112

As of both June 30, 2013 and December 31, 2012, $2.0 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

Credit Facility

As of June 30, 2013, we have a $1.0 billion credit facility that expires in April 2016. 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. 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 of no greater than 3.0 to 1.0. As of June 30, 2013, we were in compliance with these financial covenants.

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 3.1% at June 30, 2013).

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 June 30, 2013, the borrowing base under the facility was $710.0 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.

We had $520.0 million and $360.0 million outstanding under the facility at June 30, 2013 and December 31, 2012, respectively.

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 the Parent nor Finance has independent assets or operations apart from the assets and operations of its subsidiaries.

The aggregate carrying amount of our senior notes due 2019 was $499.3 million and $499.2 million at June 30, 2013 and December 31, 2012, respectively.

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 June 30, 2013 or December 31, 2012.

NOTE 9. OWNERS’ EQUITY

Units Outstanding

At June 30, 2013, owners’ equity consists of 42,599,080 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.

Issuance of Units

In January 2013, we issued 0.3 million common units related to the vesting of equity–based awards. Of this amount, 0.04 million were phantom units accounted for as liability awards, and these phantom units vested at a fair value of $2.4 million. In conjunction with the vesting of these units, we received a contribution of $0.3 million by our general partner to maintain its 2% interest in us.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Cash Distributions

The following sets forth the distributions we paid during the six months ended June 30, 2013:

Date Paid	Period Covered	Distribution per Unit		Total Distribution
February 14, 2013	October 1, 2012 – December 31, 2012	$	0.767	$	33,838
May 15, 2013	January 1, 2013 – March 31, 2013		0.768		33,883
				$	67,721

On July 29, 2013, the board of directors of EV Management declared a $0.769 per unit distribution for the second quarter of 2013 on all common units. The distribution of $33.9 million is to be paid on August 14, 2013 to unitholders of record at the close of business on August 8, 2013.

NOTE 10. NET INCOME (LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income (loss) per limited partner unit:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net income (loss)	$	32,854		$	14,956		$	(13,727	)	$	43,549
General partners’ 2% interest in net (income) loss		(657	)		(299	)		275			(871	)
Net (income) loss attributable to participating securities		(499	)		–			(998	)		–
Limited partners’ interest in net income (loss) income	$	31,698		$	14,657		$	(14,450	)	$	42,678

Weighted average limited partner units outstanding:
Common units		42,599			38,447			42,578			37,436
Class B units		–			3,873			–			3,873
Performance units		–			132			–			137
Denominator for basic net income (loss) per limited partner unit		42,599			42,452			42,578			41,446
Dilutive units ⁽¹⁾		60			226			–			293
Denominator for diluted net income (loss) per limited partner unit		42,659			42,678			42,578			41,739

Net income (loss) per limited partner unit:
Basic	$	0.74		$	0.35		$	(0.34	)	$	1.03
Diluted	$	0.74		$	0.34		$	(0.34	)	$	1.02

⁽¹⁾

Unearned performance units totaling 0.2 million units were not included in the computation of diluted net income (loss) per limited partner unit for the six months ended June 30, 2013 because the effect would have been anti–dilutive.

NOTE 11. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $2.5 million and $3.3 million in the three months ended June 30, 2013 and 2012, respectively, and $5.0 million and $6.6 million in the six months ended June 30, 2013 and 2012, 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)

W e 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 $3.6 million and $4.1 million in the three months ended June 30, 2013 and 2012, respectively, and $7.8 million and $8.1 million in the six months ended June 30, 2013 and 2012, 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 12. OTHER SUPPLEMENTAL INFORMATION

Supplemental cash flows and noncash transactions were as follows:

	Six Months Ended
	June 30,
	2013		2012
Supplemental cash flows information:
Cash paid for interest, net of capitalized interest of $3,152 and $–, respectively	$	22,311	$	25,180
Cash paid for income taxes		325		340

	As of June 30,
	2013		2012
Noncash transaction – costs for additions to oil and natural gas properties in accounts payable and accrued liabilities	$	15,100	$	15,310

Accounts payable and accrued liabilities consisted of the following:

	June 30,		December 31,
	2013		2012
Costs for additions to oil and natural gas properties	$	15,100	$	13,951
Lease operating expenses		9,948		7,309
Interest		8,800		8,566
Production and ad valorem taxes		5,098		4,379
General and administrative expenses		1,933		2,596
Current portion of ARO		1,977		1,977
Derivative settlements		1,153		364
Other		805		1,029
Total	$	44,814	$	40,171

NOTE 13. NEW ACCOUNTING STANDARDS

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2011–11, Disclosures about Offsetting Assets and Liabilities. This ASU affects all entities that have financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011–11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In January 2013, the FASB issued ASU 2013–01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, to clarify the scope of ASU 2011–11. The provisions of both ASU 2011–11 and ASU 2013–01 are applicable to annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We adopted ASU 2011–11 and 2013–01 on January 1, 2013, and the adoption did not impact our operating results, financial position or cash flows, but did impact our disclosures on offsetting arrangements (see Note 4).

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

No other new accounting pronouncements issued or effective during the six months ended June 30, 2013 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

NOTE 14. SUBSEQUENT EVENT

In August 2013, we announced that we, along with certain institutional partnerships managed by EnerVest, have signed an agreement to divest certain acreage in Ohio’s Utica Shale for $284.3 million. The acreage associated with this sale is in Guernsey, Harrison and Noble counties. Our share of the proceeds is expected to be approximately $56 million, net to our ownership interest, and we will retain our overriding royalty interests in these acres. The transaction is expected to close by the end of the third quarter and is subject to customary closing conditions and purchase price adjustments.

In August 2013, we also amended our credit facility to change our senior secured debt to EBITDAX ratio to be no greater than 3.5 to 1 through March 30, 2015 and to include certain updates related to the Dodd–Frank Act eligibility requirements for guarantors of hedging transactions.

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

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, 2012.

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.

As of December 31, 2012, our properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the San Juan Basin, Central and East Texas (which includes the Austin Chalk area), the Permian Basin, the Monroe Field in Louisiana, and Michigan. As of December 31, 2012, we had estimated net proved reserves of 13.5 MMBbls of oil, 609.5 Bcf of natural gas and 35.7 MMBbls of natural gas liquids, or 904.7 Bcfe, and a standardized measure of $866.9 million.

CURRENT DEVELOPMENTS

In the six months ended June 30, 2013, we invested $118.4 million in our unconsolidated affiliates, which included $33.3 million to increase our ownership in UEO from 8% to 21%.

In August 2013, we announced that we, along with certain institutional partnerships managed by EnerVest, have signed an agreement to divest certain acreage in Ohio’s Utica Shale for $284.3 million. The total acreage associated with this sale includes 22,535 acres in Guernsey, Harrison and Noble counties. Of that total, we are selling 4,345 acres for approximately $56 million, net to our ownership interest. We will retain our overriding royalty interests in these acres. The transaction is expected to close by the end of the third quarter and is subject to customary closing conditions and purchase price adjustments.

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.

Oil, natural gas and natural gas liquids prices have been and are expected to continue to be volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas and natural gas liquids include the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas and natural gas liquids, storage levels of natural gas and natural gas liquids and the availability and accessibility of natural gas deposits in North America.

In order to mitigate the impact of changes in 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. By removing a significant portion of this price volatility on our future production through December 2015, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

The primary factors affecting our production levels are capital availability, 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.

Utica Shale

Primarily through acquisitions completed in 2009 and 2010, we hold over 170,000 net working interest acres in Pennsylvania and Ohio and an approximate 2% average overriding royalty interest in 880,000 gross acres in Ohio which we believe may be prospective for the Utica Shale. In addition, partnerships managed by EnerVest own acreage which may be prospective for the Utica Shale. At June 30, 2013, our estimated net proved reserves in the Utica Shale were not material to us. Exploration and development activities targeting the Utica Shale are in the early stages, and it is possible that our estimates of the acreage in Ohio that we believe is prospective for the Utica Shale may change, perhaps materially, as additional exploration and development activities are conducted in the area. We do not expect to fully develop our Utica Shale properties for our account.

In mid–2012, we initiated the process for the monetization of a majority of our working interest acres related to the Utica Shale. Such monetization could take many forms, and we cannot at this time predict the type of transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our additional efforts to monetize the Utica Shale properties, it may take longer to complete the divestiture process than we expect, or we may decide to delay the monetization of all or a portion of the Utica Shale properties.

RESULTS OF OPERATIONS

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Production data:
Oil (MBbls)		245		282		508		567
Natural gas liquids (MBbls)		526		403		1,029		826
Natural gas (MMcf)		11,057		10,722		21,324		20,985
Net production (MMcfe)		15,683		14,828		30,547		29,341
Average sales price per unit:
Oil (Bbl)	$	92.56	$	90.74	$	93.03	$	95.43
Natural gas liquids (Bbl)		28.83		34.48		29.59		40.59
Natural gas (Mcf)		3.84		2.18		3.53		2.48
Mcfe		5.12		4.23		5.01		4.76
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.67	$	1.68	$	1.71	$	1.82
Production taxes		0.19		0.17		0.19		0.20
Total		1.86		1.85		1.90		2.02
Depreciation, depletion and amortization		1.76		1.91		1.92		1.81
General and administrative expenses		0.58		0.68		0.71		0.76

Three Months Ended June 30, 2013 Compared with the Three Months Ended June 30, 2012

Net income for the three months ended June 30, 2013 was $32.9 million compared with $15.0 million for the three months ended June 30, 2012. This change reflects (i) an $18.0 million increase in total revenues, (ii) a $13.4 million decrease in impairments of our oil and natural gas properties, (iii) a $14.7 million favorable non–cash change in the fair value of our derivatives, and (iv) a $1.0 million decrease in interest expense, partially offset by (v) a $30.1 million reduction in realized gains on our derivatives.

O il, natural gas and natural gas liquids revenues for the three months ended June 30, 2013 totaled $80.3 million, an increase of $17.5 million compared with the three months ended June 30, 2012. This was the result of increases of $18.3 million related to higher prices for oil and natural gas and $4.8 million related to increased natural gas and natural gas liquids production offset by decreases of $2.3 million related to lower prices for natural gas liquids and $3.3 million related to decreased oil production.

Lease operating expenses for the three months ended June 30, 2013 increased $1.4 million compared with the three months ended June 30, 2012 primarily due to costs associated with the increased natural gas and natural gas liquids production. Lease operating expenses per Mcfe were $1.67 in the three months ended June 30, 2013 compared with $1.68 in the three months ended June 30, 2012.

Dry hole and exploration costs for the three months ended June 30, 2013 decreased $0.8 million compared with the three months ended June 30, 2012 primarily as a result of lower seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the three months ended June 30, 2013 increased $0.4 million compared with the three months ended June 30, 2012 primarily due to increased oil, natural gas and natural gas liquids revenues. Production taxes for the three months ended June 30, 2013 were $0.19 per Mcfe compared with $0.17 per Mcfe for the three months ended June 30, 2012.

DD&A for the three months ended June 30, 2013 decreased $0.7 million compared with the three months ended June 30, 2012 due to $2.2 million from a lower DD&A rate offset by $1.5 million from increased production. The DD&A rate is computed based on the preceding 12 month average price for oil, natural gas and natural gas liquids. The lower average DD&A rate per unit reflects the impact that higher natural gas prices had on our reserves estimates and increased reserves from our Barnett Shale drilling program. DD&A for the three months ended June 30, 2013 was $1.76 per Mcfe compared with $1.91 per Mcfe for the three months ended June 30, 2012.

General and administrative expenses for the three months ended June 30, 2013 totaled $9.1 million, a decrease of $1.0 million compared with the three months ended June 30, 2012. This decrease is primarily the result of $0.8 million of lower fees paid to EnerVest under the omnibus agreement and $0.6 million of decreased due diligence costs partially offset by $0.5 million of increased equity compensation costs. General and administrative expenses were $0.58 per Mcfe in the three months ended June 30, 2013 compared with $0.68 per Mcfe in the three months ended June 30, 2012.

In the three months ended June 30, 2013, we incurred leasehold impairment charges of $2.8 million. In the three months ended June 30, 2012, we incurred $0.1 million of charges related to expired leases and a $16.2 million impairment charge 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 from proved reserves. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk – adjusted discount rates and other relevant data.

Realized gains on derivatives, net consisted of the following for the three months ended June 30:

	2013			2012

Cash settlements	$	4,949		$	35,323
Non–cash realized loss related to acquired derivatives		–			(720	)
Non–cash realized loss related to terminated interest rate swaps		(488	)		–
Realized gains on derivatives, net	$	4,461		$	34,603

The $30.4 million decrease in cash settlements is due to the impact of derivative contracts with more favorable terms that expired as of December 31, 2012 and, to a lesser extent, higher natural gas prices.

Unrealized gains (losses) on derivatives, net consisted of the following for the three months ended June 30:

	2013		2012

Change in the fair value of open derivatives	$	29,798	$	14,817
Change in value of acquired derivatives from the beginning of the period		–		720
Change in value of terminated interest rate swaps		488		–
Unrealized gains (losses) on derivatives, net	$	30,286	$	15,537

Interest expense for the three months ended June 30, 2013 decreased $1.0 million compared with the three months ended June 30, 2012 due to an increase of $2.4 million in capitalized interest and a decrease of $2.2 million from a lower weighted average interest rate offset by an increase of $3.6 million from a higher weighted average long–term debt balance.

Six Months Ended June 30, 2013 Compared with the Six Months Ended June 30, 2012

Net (loss) income for the six months ended June 30, 2013 was $(13.7) million compared with $43.5 million for the six months ended June 30, 2012. This change reflects (i) a $35.2 million adverse non–cash change in the fair value of our derivatives, (ii) a $43.6 million reduction in realized gains on our derivatives, and (iii) a $5.5 million increase in DD&A expense, partially offset by (iv) a $14.0 million increase in total revenues, (v) an $8.9 million decrease in impairments of our oil and natural gas properties and (vi) a $2.5 million decrease in dry hole and exploration costs.

O il, natural gas and natural gas liquids revenues for the six months ended June 30, 2013 totaled $153.0 million, an increase of $13.4 million compared with the six months ended June 30, 2012. This was the result of increases of $22.1 million related to higher prices for natural gas and $7.2 million related to increased natural gas and natural gas liquids production offset by decreases of $10.4 million related to lower prices for oil and natural gas liquids and $5.5 million related to decreased oil production.

Lease operating expenses for the six months ended June 30, 2013 decreased $1.1 million compared with the six months ended June 30, 2012 as the result of $1.7 million ($0.06 per Mcfe) of costs in the six months ended June 30, 2012 associated with the sales of oil in tanks acquired in certain of our 2011 acquisitions, partially offset by costs associated with the increased natural gas and natural gas liquids production . Lease operating expenses per Mcfe were $1.71 in the six months ended June 30, 2013 compared with $1.82 in the six months ended June 30, 2012.

Dry hole and exploration costs for the six months ended June 30, 2013 decreased $2.5 million compared with the six months ended June 30, 2012 primarily as a result of decreased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin.

DD&A for the six months ended June 30, 2013 increased $5.5 million compared with the six months ended June 30, 2012 due to $3.2 million from a higher DD&A rate and $2.3 million from increased production. The higher DD&A rate per unit reflects the impact that lower average 12 month natural gas prices had on our reserves estimates. DD&A for the six months ended June 30, 2013 was $1.92 per Mcfe compared with $1.81 per Mcfe for the six months ended June 30, 2012.

General and administrative expenses for the six months ended June 30, 2013 totaled $21.7 million, a decrease of $0.5 million compared with the six months ended June 30, 2012. This decrease is primarily the result of $1.5 million of lower fees paid to EnerVest under the omnibus agreement and $0.8 million of decreased due diligence costs partially offset by $1.4 million of higher compensation costs primarily related to our equity–based compensation plans. General and administrative expenses were $0.71 per Mcfe in the six months ended June 30, 2013 compared with $0.76 per Mcfe in the six months ended June 30, 2012.

In the six months ended June 30, 2013, we incurred leasehold impairment charges of $8.0 million. In the six months ended June 30, 2012, we incurred $0.2 million of leasehold impairment charges, $0.4 million of additional impairment charges to write down assets held for sale to their fair value and a $16.2 million impairment charge 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 from proved reserves. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk – adjusted discount rates and other relevant data.

Realized gains on derivatives, net consisted of the following for the six months ended June 30:

	2013			2012

Cash settlements	$	16,388		$	60,097
Non–cash realized loss related to acquired derivatives		–			(1,304	)
Non–cash realized loss related to terminated interest rate swaps		(1,168	)		–
Realized gains on derivatives, net	$	15,220		$	58,793

The $43.7 million decrease in cash settlements is due to the impact of derivative contracts with more favorable terms that expired as of December 31, 2012 and, to a lesser extent, higher natural gas prices.

Unrealized gains (losses) on derivatives, net consisted of the following for the six months ended June 30:

	2013			2012

Change in the fair value of open derivatives	$	(9,155	)	$	25,894
Change in value of acquired derivatives from the beginning of the period		–			1,304
Change in value of terminated interest rate swaps		1,168			–
Unrealized gains (losses) on derivatives, net	$	(7,987	)	$	27,198

Interest expense for the six months ended June 30, 2013 increased $0.8 million compared with the six months ended June 30, 2012 due to an increase of $4.9 million from a higher weighted average long–term debt balance offset by a decrease of $0.9 million due to a lower weighted average effective interest rate and an increase in capitalized interest in the six months ended June 30, 2013 of $3.2 million.

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. For 2013, 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.

In the past we accessed the equity and debt markets to finance our significant acquisitions. While we have been successful in accessing the public equity and debt markets in 2012 and in prior years, any disruptions in the financial markets may limit our ability to access the public equity or debt markets in the future.

Long–term Debt

As of June 30, 2013, we have a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of June 30, 2013, the borrowing base was $710.0 million, and we had $520.0 million outstanding.

As of June 30, 2013, we have $500.0 million in aggregate principal amount outstanding of 8.0% senior notes due 2019, and the aggregate carrying amount of the senior notes due 2019 was $499.3 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 June 30, 2013, we had $8.3 million of cash and short–term investments, which included $3.9 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with a major financial institution.

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 June 30, 2013, 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:

	Six Months Ended June 30,
	2013			2012
Operating activities	$	70,407		$	113,040
Investing activities		(162,229	)		(101,076	)
Financing activities		92,613			(12,644	)

Operating Activities

Cash flows from operating activities provided $70.4 million and $113.0 million in the six months ended June 30, 2013 and 2012, respectively. The significant factor in the decrease was $43.7 million of decreased cash settlements from our derivatives.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the six months ended June 30, 2013, we spent $51.8 million for additions to our oil and natural gas properties and increased our investment in unconsolidated affiliates by $118.4 million. In addition, we received $8.0 million in final purchase price settlements related to our August 2012 acquisition of additional working interests in acreage in Ohio.

During the six months ended June 30, 2012, we spent $35.7 million for acquisitions of oil and natural gas properties and $62.6 million for additions to our oil and natural gas properties. We also increased our investment in unconsolidated affiliates by $11.9 million. In addition, we received $5.5 million from the sale of oil and natural gas properties and $3.7 million from the settlements of acquired derivatives.

Financing Activities

During the six months ended June 30, 2013, we received $160.0 million from borrowings under our credit facility and paid distributions of $67.7 million to holders of our common units and our general partner.

During the six months ended June 30, 2012, we received proceeds of $262.5 million, after payment of offering costs of $0.3 million, from our public equity offering in February 2012 and $202.0 million, after payment of offering costs of $4.0 million, from our debt offering in March 2012. We used the proceeds to repay $460.0 million of indebtedness outstanding under our credit facility. We also received $40.0 million from borrowings under our credit facility and contributions of $5.7 million from our general partner in order to maintain its 2% interest in us. In addition, we paid distributions of $62.8 million to holders of our common units, Class B 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;

our business strategy and plans, including plans for the sale of acreage in the Utica Shale;

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;

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;

availability of drilling and production equipment;

marketing of oil, natural gas and natural gas liquids;

developments in oil and natural gas producing countries;

competition;

general economic conditions;

governmental regulations;

receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instrument contracts;

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

events similar to those of September 11, 2001;

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 of Form 10–K for the year ended December 31, 2012. This document is available through our website or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at http://www.sec.gov.

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, oil, natural gas and natural gas liquids 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 2015. As of June 30, 2013, we have commodity contracts covering approximately 73% of our production attributable to our estimated net proved reserves from July 2013 through December 2015, 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 June 30, 2013 was a net asset of $83.8 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 $59.0 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 June 30, 2013 would have increased by approximately $2.3 million. The fair value of our interest rate swaps at June 30, 2013 was a liability of $6.3 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 $2.2 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(e) and 15d–15(e), 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 June 30, 2013 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 June 30, 2013 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, 2012.

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

We adopted both ASU 2011–11, Disclosures about Offsetting Assets and Liabilities , and ASU 2013–01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, as of January 1, 2013. These ASUs affect all entities that have financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement, and require an entity to disclose information about offsetting and related arrangements to enable user of its financial statements to understand the effect of those arrangements on its financial position. The provisions of both ASUs were to be applied retrospectively for all comparable periods presented. The impact of retrospectively adjusting for the adoption of the ASUs was not material to our historical consolidated financial statements.

The following table sets forth the unaudited retrospective application of these ASUs as of December 31, 2011:

						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 December 31, 2011:
Derivative asset	$	85,289	$	(3,517	)	$	81,772
Long–term derivative asset		67,217		(9,574	)		57,643
Total	$	152,506	$	(13,091	)	$	139,415

						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 December 31, 2011:
Derivative liability	$	4,135	$	(3,517	)	$	618
Long–term derivative liability		9,574		(9,574	)		–
Total	$	13,709	$	(13,091	)	$	618

ITEM 6. EXHIBITS

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

+10.1	Fifth Amendment dated as of August 7, 2013 to Second Amended and Restated Credit Agreement.

+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)

	By:	/s/ VIPUL DHADDA
		Name: Vipul Dhadda
		Title: Authorized Signatory

Date: August 9, 2013	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

+10.1	Fifth Amendment dated as of August 7, 2013 to Second Amended and Restated Credit Agreement.

+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 10.1

FIFTH AMENDMENT

SECOND AMENDED AND RESTATED CREDIT AGREEMENT

DATED AS OF

AUGUST 7, 2013

AMONG

EV PROPERTIES, L.P.,

as Borrower,

THE GUARANTORS,

JPMORGAN CHASE BANK, N.A.,

as Administrative Agent,

and

The Lenders Signatory Hereto

FIFTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT

This FIFTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT (this “ Fifth Amendment ”) dated as of August 7, 2013, is among EV PROPERTIES, L.P., a Delaware limited partnership (the “ Borrower ”); each of the undersigned guarantors (the “ Guarantors ”, and together with the Borrower, the “ Obligors ”); JPMORGAN CHASE BANK, N.A., as administrative agent for the Lenders (in such capacity, together with its successors, the “ Administrative Agent ”); and the Lenders signatory hereto.

Recitals

A. The Borrower, the Administrative Agent and the Lenders are parties to that certain Second Amended and Restated Credit Agreement dated as of April 26, 2011 (as amended by that certain First Amendment to Second Amended and Restated Credit Agreement dated as of December 21, 2011, by that certain Second Amendment to Second Amended and Restated Credit Agreement dated as of March 29, 2012, by that certain Third Amendment to Second Amended and Restated Credit Agreement dated as of September 27, 2012 and by that certain Fourth Amendment to Second Amended and Restated Credit Agreement dated as of February 26, 2013, the “ Credit Agreement ”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.

B. The Guarantors are parties to that certain Second Amended and Restated Guaranty and Collateral Agreement dated as of April 26, 2011 made by the Borrower and each of the other Obligors in favor of the Administrative Agent (as heretofore amended, modified or supplemented, the “ Guaranty Agreement ”).

C. The Borrower, the Administrative Agent and the Lenders have agreed to amend certain provisions of the Credit Agreement as more fully set forth herein.

D. NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1. Defined Terms . Each capitalized term which is defined in the Credit Agreement, but which is not defined in this Fifth Amendment, shall have the meaning ascribed such term in the Credit Agreement. Unless otherwise indicated, all section references in this Fifth Amendment refer to sections of the Credit Agreement.

Section 2. Amendments to Credit Agreement .

2.1 Amendments to Section 1.02 .

(a) The definition of “Agreement” is hereby amended in its entirety to read as follows:

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“ Agreement ” means this Second Amended and Restated Credit Agreement, including the Schedules and Exhibits hereto, as amended by the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, and as the same may be amended, modified or supplemented from time to time.

(b) The definition of “Indebtedness” is hereby amended by adding the following proviso in place of the period at the end thereto:

“; provided, however, that the definition of ‘Indebtedness’ shall not create any guarantee by any Guarantor of (or grant of security interest by any Guarantor to support, as applicable) any Excluded Swap Obligations of such Guarantor for purposes of determining any obligations of any Guarantor.”

“ Commodity Exchange Act ” means the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute.

“ Excluded Swap Obligation ” means, with respect to any Guarantor, any Swap Obligation if, and to the extent that, all or a portion of the guarantee of such Guarantor of, or the grant by such Guarantor of a security interest to secure, such Swap Obligation (or any guarantee thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) (a) by virtue of such Guarantor’s failure for any reason to constitute an “eligible contract participant” as defined in the Commodity Exchange Act and the regulations thereunder at the time the guarantee of such Guarantor or the grant of such security interest becomes or would become effective with respect to such obligation or liability in respect of a Secured Hedge Agreement or (b) in the case of an obligation or liability in respect of a Secured Hedge Agreement that is required to be cleared pursuant to Section 2(h) of the Commodity Exchange Act (or any successor provision thereto), because such Guarantor is a “financial entity,” as defined in Section 2(h)(7)(C)(i) the Commodity Exchange Act (or any successor provision thereto), at the time the guarantee of (or grant of security interest by, as applicable) such Guarantor becomes or would become effective with respect to such Swap Obligation. If a Swap Obligation arises under a master agreement governing more than one Swap Agreement, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to Swap Agreements for which such guarantee or security interest is or becomes illegal.

“ Fifth Amendment ” means that certain Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of August 7, 2013, among the Borrower, the Guarantors, the Administrative Agent and the Lenders party thereto.

“ Fifth Amendment Effective Date ” has the meaning set forth in the Fifth Amendment.

Page 2

“ Qualified ECP Guarantor ” means, in respect of any Swap Obligation, the Borrower and each Guarantor that, at the time the relevant guaranty obligation or other liability (or grant of the relevant security interest, as applicable) becomes or would become effective with respect to such obligation or liability, has total assets exceeding $10,000,000 or otherwise constitutes an “eligible contract participant” under the Commodity Exchange Act or any regulations promulgated thereunder and can cause another person to qualify as an “eligible contract participant” with respect to such Swap Obligation at such time by entering into a keepwell pursuant to section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

“ Swap Obligation ” shall mean, with respect to any person, any obligation to pay or perform under any Swap Agreement.

2.2 Amendment to Article VIII .

(a) Article VIII is hereby amended by inserting the following new Section 8.18 at the end thereto:

“Section 8.18 Keepwell . The Parent will, and will cause each Qualified ECP Guarantor to, provide such funds or other support as may be needed from time to time by the Borrower or each Guarantor to honor all of its obligations under this Agreement or any Swap Agreements (provided, however, that each Qualified ECP Guarantor shall only be liable under this Section 8.18 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 8.18 or otherwise voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount). The obligations of each Qualified ECP Guarantor under this Section 8.18 shall remain in full force and effect until payment in full of the Indebtedness and the termination of this Agreement. The Borrower intends that this Section 8.18 constitute, and this Section 8.18 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Credit Party for all purposes of section 1a(18)(A)(v)(II) of the Commodity Exchange Act.”

2.3 Amendments to Section 9.01 .

(a) Section 9.01(a) is hereby amended in its entirety to read as follows:

(a) Ratio of Total Debt to EBITDAX . The Parent will not, as of any date of determination from and after March 31, 2015, permit its ratio of Total Debt as of such date to EBITDAX for the most recent period of four fiscal quarters for which financial statements are available to be greater than 4.25 to 1.0.

(b) Section 9.01(c) is hereby added which reads in its entirety as follows:

(c) Ratio of Senior Secured Funded Debt to EBITDAX . The Parent will not, as of any date of determination from and after the Fifth Amendment Effective Date up to and including March 30, 2015, permit its ratio of Senior Secured Funded Debt as of such date to EBITDAX for the most recent period of four fiscal quarters for which financial statements are available to be greater than 3.5 to 1.0.

Page 3

Section 3. Additional Amendment to Credit Agreement Upon Approval of All Lenders . If the Administrative Agent shall have received executed counterpart signature pages to this Amendment from all of the Lenders, then Section 10.02(c) of the Credit Agreement is hereby further amended by inserting the following new sentence immediately following the paragraph that begins with the word “fifth”:

“Notwithstanding the foregoing, amounts received from the Borrower or any other Guarantor that is not a Qualified ECP Guarantor shall not be applied to any Excluded Swap Obligations.”

Section 4. Conditions Precedent . This Fifth Amendment shall become effective on the date (such date, the “ Fifth Amendment Effective Date ”) when each of the following conditions is satisfied (or waived in accordance with Section 12.02):

4.1 The Administrative Agent shall have received from the Majority Lenders and the Obligors counterparts (in such number as may be requested by the Administrative Agent) of this Fifth Amendment signed on behalf of such Persons.

4.2 Both before and immediately after giving effect to this Fifth Amendment, no Default shall have occurred and be continuing.

4.3 The Administrative Agent shall have received such other documents as the Administrative Agent or its special counsel may reasonably require.

The Administrative Agent is hereby authorized and directed to declare this Fifth Amendment to be effective (and the Fifth Amendment Effective Date shall occur) when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 4 or the waiver of such conditions as permitted in Section 12.02. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes.

For the avoidance of doubt, the amendment to Section 10.02(c) of the Credit Agreement set forth in Section 3 of this Amendment shall only be implemented if (a) the Fifth Amendment Effective Date shall have occurred and (b) the Administrative Agent shall have received executed counterpart signature pages to this Amendment from all of the Lenders and the Obligors.

Section 5. Miscellaneous .

5.1 Confirmation . The provisions of the Credit Agreement, as amended by this Fifth Amendment, shall remain in full force and effect following the Fifth Amendment Effective Date.

Page 4

5.2 Ratification and Affirmation; Representations and Warranties . Each Obligor hereby (a) acknowledges the terms of this Fifth Amendment; (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document and agrees that each Loan Document remains in full force and effect as expressly amended hereby; (c) agrees that from and after the Fifth Amendment Effective Date each reference to the Credit Agreement in the Guaranty Agreement and the other Loan Documents shall be deemed to be a reference to the Credit Agreement, as amended by this Fifth Amendment; and (d) represents and warrants to the Lenders that as of the date hereof: (i) all of the representations and warranties contained in each Loan Document are true and correct in all material respects (without duplication of materiality), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects (without duplication of materiality) as of such specified earlier date, (ii) no Default has occurred and is continuing and (iii) no event, development or circumstance has have occurred or exists that has resulted in, or could reasonably be expected to have, a Material Adverse Effect.

5.3 Counterparts . This Fifth Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Fifth Amendment by telecopy, facsimile or email transmission shall be effective as delivery of a manually executed counterpart of this Fifth Amendment.

5.4 No Oral Agreement . This Fifth Amendment, the Credit Agreement and the other Loan Documents executed in connection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties. There are no subsequent oral agreements between the parties.

5.5 GOVERNING LAW . THIS FIFTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

5.6 Payment of Expenses . In accordance with Section 12.03, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable out-of-pocket costs and reasonable expenses incurred in connection with this Fifth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

5.7 Severability . Any provision of this Fifth Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

5.8 Successors and Assigns . This Fifth Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[ Signature Pages Follow ]

Page 5

IN WITNESS WHEREOF, the parties hereto have caused this Fifth Amendment to be duly executed effective as of the Fifth Amendment Effective Date.

BORROWER:	EV PROPERTIES, L.P.

	By:	EV Properties GP, LLC, its general partner

	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief
		Financial Officer

PARENT:	EV ENERGY PARTNERS, L.P.

	By:	EV ENERGY GP, L.P.,
		its general partner

		By: EV MANAGEMENT, LLC, its general partner

	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief
		Financial Officer

GUARANTORS:	EV PROPERTIES GP, LLC

	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief
		Financial Officer

	ENERVEST PRODUCTION
	PARTNERS, LTD.

	By:	EVPP GP, LLC,
		its general partner

	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief
		Financial Officer