Harvest Oil & Gas Corp. - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - Harvest Oil & Gas Corp.	Financial_Report.xls
EX-32.1 - EXHIBIT 32.1 - Harvest Oil & Gas Corp.	v314874_ex32-1.htm
EX-32.2 - EXHIBIT 32.2 - Harvest Oil & Gas Corp.	v314874_ex32-2.htm
EX-31.2 - EXHIBIT 31.2 - Harvest Oil & Gas Corp.	v314874_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - Harvest Oil & Gas Corp.	v314874_ex31-1.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

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 o

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 o

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 o

Non-accelerated filer o

Smaller reporting company o

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

YES o NO þ

As of August 3, 2012, the registrant had 38,447,350 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	23
Item 4.	Controls and Procedures	24

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	24
Item 1A.	Risk Factors	24
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24
Item 3.	Defaults Upon Senior Securities	24
Item 4.	Mine Safety Disclosures	24
Item 5.	Other Information	25
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,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	29,632		$	30,312
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		29,630			36,926
Other		3,530			459
Derivative asset		89,604			81,772
Other current assets		1,910			3,084
Assets held for sale		69			6,597
Total current assets		154,375			159,150

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; June 30, 2012, $313,199; December 31, 2011, $244,092		1,807,512			1,768,529
Other property, net of accumulated depreciation and amortization; June 30, 2012, $526; December 31, 2011, $447		1,356			1,345
Long–term derivative asset		75,088			57,643
Other assets		23,684			16,557
Total assets	$	2,062,015		$	2,003,224

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Third party	$	45,910		$	34,705
Related party		1,389			870
Derivative liability		–			618
Liabilities held for sale		–			602
Total current liabilities		47,299			36,795

Asset retirement obligations		94,879			90,803
Long–term debt		739,184			953,023
Long–term liabilities		1,879			2,564

Commitments and contingencies

Owners’ equity:
Common unitholders – 38,447,350 units and 34,173,650 units issued and outstanding as of June 30, 2012 and December 31, 2011, respectively		1,190,712			935,425
Class B unitholders – 3,873,357 units issued and outstanding as of June 30, 2012 and December 31, 2011		(1,649	)		232
General partner interest		(10,289	)		(15,618	)
Total owners’ equity		1,178,774			920,039
Total liabilities and owners’ equity	$	2,062,015		$	2,003,224

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues:
Oil, natural gas and natural gas liquids revenues	$	62,793		$	68,109		$	139,594		$	127,730
Transportation and marketing–related revenues		759			1,484			1,689			2,885
Total revenues		63,552			69,593			141,283			130,615

Operating costs and expenses:
Lease operating expenses		24,850			17,949			53,450			35,311
Cost of purchased natural gas		501			1,120			1,146			2,170
Dry hole and exploration costs		1,682			441			3,855			844
Production taxes		2,525			3,119			5,807			5,770
Asset retirement obligations accretion expense		1,220			970			2,428			1,936
Depreciation, depletion and amortization		28,395			18,443			52,986			36,007
General and administrative expenses		10,149			7,132			22,266			15,725
Impairment of oil and natural gas properties		16,264			5,078			16,899			6,666
Total operating costs and expenses		85,586			54,252			158,837			104,429

Operating (loss) income		(22,034	)		15,341			(17,554	)		26,186

Other income (expense), net:
Realized gains on derivatives, net		34,603			14,242			58,793			27,784
Unrealized gains (losses) on derivatives, net		15,537			17,422			27,198			(35,633	)
Interest expense		(12,595	)		(8,124	)		(23,679	)		(13,283	)
Other (expense) income, net		(30	)		313			(26	)		233
Total other income (expense), net		37,515			23,853			62,286			(20,899	)

Income before income taxes and equity in losses of unconsolidated affiliates		15,481			39,194			44,732			5,287

Income taxes		(439	)		(31	)		(1,097	)		(113	)

Income before equity in losses of unconsolidated affiliates		15,042			39,163			43,635			5,174

Equity in losses of unconsolidated affiliates		(86	)		–			(86	)		–

Net income	$	14,956		$	39,163		$	43,549		$	5,174
General partner’s interest in net income, including incentive distribution rights	$	299		$	3,728		$	871		$	5,982
Limited partners’ interest in net income (loss)	$	14,657		$	35,435		$	42,678		$	(808	)

Net income (loss) per limited partner unit:
Basic	$	0.35		$	1.03		$	1.03		$	(0.02	)
Diluted	$	0.34		$	1.03		$	1.02		$	(0.02	)

Weighted average limited partner units outstanding:
Basic		42,452			34,294			41,446			33,002
Diluted		42,678			34,534			41,739			33,002

Distributions declared per unit	$	0.765		$	0.761		$	1.529		$	1.521

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)

	Common Unitholders			Class B Unitholders			General Partner Interest			Total Owners’ 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

	Common Unitholders			General Partner Interest			Total Owners’ Equity

Balance, December 31, 2010	$	779,327		$	(5,380	)	$	773,947
Conversion of 80,534 vested phantom units		3,508			–			3,508
Proceeds from public equity offering, net of underwriters discount and offering costs of $308		146,800			–			146,800
Contributions from general partner		–			3,191			3,191
Distributions		(49,291	)		(6,682	)		(55,973	)
Equity–based compensation		2,428			–			2,428
Net income		5,071			103			5,174
Balance, June 30, 2011	$	887,843		$	(8,768	)	$	879,075

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,
	2012			2011

Cash flows from operating activities:
Net income	$	43,549		$	5,174
Adjustments to reconcile net income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		2,428			1,936
Depreciation, depletion and amortization		52,986			36,007
Equity–based compensation cost		8,096			3,877
Impairment of oil and natural gas properties		16,899			6,666
Noncash derivative activity		(27,198	)		30,951
Equity in losses of unconsolidated affiliates		86			–
Other, net		3,948			793
Changes in operating assets and liabilities:
Accounts receivable		4,225			(12,866	)
Other current assets		365			111
Accounts payable and accrued liabilities		9,758			7,630
Other, net		(2,102	)		(149	)
Net cash flows provided by operating activities		113,040			80,130

Cash flows from investing activities:
Acquisition of oil and natural gas properties		(35,728	)		3,101
Additions to oil and natural gas properties		(62,566	)		(33,686	)
Proceeds from sale of oil and natural gas properties		5,489			1,170
Investments in unconsolidated affiliates		(11,947	)		–
Settlements from acquired derivatives		3,676			2,834
Earnest money received for sale of oil and natural gas properties		–			900
Net cash flows used in investing activities		(101,076	)		(25,681	)

Cash flows from financing activities:
Long–term debt borrowings		40,000			–
Repayment of long–term debt borrowings		(460,000	)		(431,500	)
Proceeds from debt offering		206,000			292,500
Loan costs paid		(4,078	)		(6,202	)
Proceeds from public equity offering		262,833			147,108
Offering costs		(304	)		(308	)
Contributions from general partner		5,714			3,191
Distributions paid		(62,809	)		(55,973	)
Net cash flows used in financing activities		(12,644	)		(51,184	)

(Decrease) increase in cash and cash equivalents		(680	)		3,265
Cash and cash equivalents – beginning of period		30,312			23,127
Cash and cash equivalents – end of period	$	29,632		$	26,392

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. (“we,” “our” or “us”) is 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.

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. Accordingly, certain information and disclosures normally included in 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, 2011.

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 account for the phantom units issued prior to 2009 as liability awards, and the fair value of these phantom units is 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 is recognized for these phantom units based on the proportionate amount of the requisite service period that has been rendered to date. 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 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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Liability awards	$	357	$	526	$	1,180	$	1,449
Equity awards		3,459		1,214		6,916		2,428
Total	$	3,816	$	1,740	$	8,096	$	3,877

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)

As of June 30, 2012, total unrecognized compensation costs related to the unvested liability awards and equity awards and the period over which they are expected to be recognized are as follows:

	Unrecognized Compensation Expense		Weighted Average Period (in years)
Liability awards	$	1,102		0.5
Equity awards		36,691		2.8

NOTE 3. ACQUISITIONS AND DIVESTITURE

In February 2012 and March 2012, we, along with certain institutional partnerships managed by EnerVest, had additional closings on the oil and natural gas properties in the Barnett Shale that we acquired in December 2011. We acquired a 31.63% proportional interest in these properties for an aggregate purchase price of $36.5 million, subject to customary purchase price adjustments. Pro forma results of operations have not been presented as the amounts would not be material to our unaudited condensed consolidated statements of operations.

In March 2012, we sold a portion of the assets and liabilities held for sale for $5.5 million.

In April 2012, we received final purchase price settlements of $1.7 million related to our acquisitions of oil and natural gas properties in the Barnett Shale in December 2011.

In May 2012, we paid a final purchase price settlement of $0.9 million related to our acquisition of oil and natural gas properties in the Mid–Continent area in November 2011.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

We own 9.0% of Cardinal Gas Services, LLC (“Cardinal”), which is constructing the gathering systems for production generated from the assets in which a partial interest was sold in the December 2011 transaction with Total E&P USA, Inc. and Chesapeake Energy Corporation (the “Total Transaction”). We also own 8% of Utica East Ohio Midstream LLC (“UEO”), which is constructing the natural gas processing plant, natural gas liquids fractionation plant, and connecting pipelines for the assets that are part of the Total Transaction. It is expected that the UEO facilities will also process third party production. We account for our investments in Cardinal and UEO using the equity method of accounting. Accordingly, we recognize our proportionate share of the earnings or losses of Cardinal and UEO in the period in which they are reported by Cardinal and UEO in their financial statements rather than in the period in which Cardinal and UEO declare a dividend. Dividends received from Cardinal and UEO decrease the carrying amount of our investments.

As of June 30, 2012 and December 31, 2011, the carrying amount of our investments was $12.4 million and $0.5 million, respectively, and is included in “Other assets” in our unaudited condensed consolidated balance sheets.

NOTE 5. 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 changes 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 net income as “Unrealized gains (losses) on derivatives, net” in our unaudited condensed consolidated statements of operations.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

As of June 30, 2012, we had entered into commodity contracts with the following terms:

Period Covered	Hedged Volume		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (MBbls):
Swaps – July 2012 to December 2012		509.7	$	95.80	$		$
Collars – July 2012 to December 2012		229.6				104.54		156.77
Swaps – 2013		1,532.8		89.08
Swaps – 2014		1,152.7		91.35

Natural Gas (MmmBtus):
Swaps – July 2012 to December 2012		16,762.4		4.84
Collars – July 2012 to December 2012		3,327.5				7.94		9.90
Swaps – 2013		35,879.5		4.95
Swaps – 2014		15,184.0		5.73
Swaps – 2015		15,147.5		5.97

Ethane (MBbls):
Swaps – July 2012 to December 2012		368.0		29.18

Propane (MBbls):
Swap – July 2012 to December 2012		184.0		53.97

As of June 30, 2012, we had entered into interest rate swaps with the following terms:

Period Covered	Notional Amount		Floating Rate	Fixed Rate
July 2012	$	90,000	1 Month LIBOR		4.157	%
July 2012 – September 2012		40,000	1 Month LIBOR		2.145	%
July 2012 – July 2015		110,000	1 Month LIBOR		3.315	%

The fair value of these derivatives was as follows:

	Asset Derivatives						Liability Derivatives
	June 30, 2012			December 31, 2011			June 30, 2012			December 31, 2011
Commodity contracts	$	173,967		$	152,506		$	–		$	3,699
Interest rate swaps		–			–			9,275			10,010
Total fair value		173,967			152,506			9,275			13,709
Netting arrangements		(9,275	)		(13,091	)		(9,275	)		(13,091	)
Net recorded fair value	$	164,692		$	139,415		$	–		$	618

Location of derivatives in our unaudited condensed consolidated balance sheets:
Derivative asset	$	89,604		$	81,772		$	–		$	–
Long–term derivative asset		75,088			57,643			–			–
Derivative liability		–			–			–			618
	$	164,692		$	139,415		$	–		$	618

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, 2012 and December 31, 2011, 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Realized gains on derivatives, net:
Commodity contracts ⁽¹⁾	$	35,646		$	11,388		$	60,952		$	27,070
Interest rate swaps ⁽²⁾		(1,043	)		2,854			(2,159	)		714
Total	$	34,603		$	14,242		$	58,793		$	27,784

Unrealized gains (losses) on derivatives, net:
Commodity contracts	$	15,308		$	20,380		$	26,462		$	(34,181	)
Interest rate swaps ⁽²⁾		229			(2,958	)		736			(1,452	)
Total	$	15,537		$	17,422		$	27,198		$	(35,633	)

⁽¹⁾

Excludes $0.7 million and $1.4 million for the three months ended June 30, 2012 and 2011, respectively, and $1.3 million and $2.9 million for the six months ended June 30, 2012 and 2011, respectively, related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives.

⁽²⁾

In June 2011, we terminated three of our interest rate swaps and reclassified the $4.7 million non–cash gain from “Unrealized gains (losses) on derivatives, net” to “Realized gains on derivatives, net.”

NOTE 6. FAIR VALUE MEASUREMENTS

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

Recurring Basis

			Fair Value Measurements at the End of the Reporting Period
	Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of June 30, 2012:
Assets – Commodity contracts	$	173,967	$	–	$	173,967	$	–

Liabilities – Interest rate swaps:	$	9,275	$	–	$	9,275	$	–

As of December 31, 2011:
Assets – Commodity contracts	$	152,506	$	–	$	152,506	$	–

Liabilities:
Commodity contracts	$	3,699		–	$	3,699	$	–
Interest rate swaps		10,010		–		10,010		–
	$	13,709	$	–	$	13,709	$	–

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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 three months ended June 30, 2012.

Nonrecurring Basis

In March 2012, in conjunction with the sale of assets held for sale, we incurred an additional impairment charge of $0.4 million to write down assets held for sale with a carrying amount of $6.5 million 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. These impairment charges were included in earnings for the three months and six months ended June 30, 2012. The fair value was determined 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 oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk–adjusted discount rates and other relevant data.

In March 2011, in conjunction with the sale of oil and natural gas properties, we incurred an impairment charge of $1.5 million to write down oil and natural gas properties with a carrying amount of $2.7 million to their fair value of $1.2 million. The impairment charge was included in earnings for the six months ended June 30, 2011. 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 2011, we incurred an impairment charge of $5.2 million to write down oil and natural gas properties with a carrying amount of $13.7 million to their fair value of $8.5 million. The impairment charge was included in earnings for the six months ended June 30, 2011. 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.

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, 2012 and December 31, 2011, the estimated fair value of our senior notes due 2019 was $497.5 million and $306.8 million, respectively, which differs from the carrying value of $499.2 million and $293.0 million, respectively. The fair value of the senior notes due 2019 was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to us at the end of each respective period.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 7. 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:

Balance as of December 31, 2011	$	93,225
Liabilities incurred		655
Accretion expense		2,428
Revisions in estimated cash flows		1,056
Settlements and divestitures		(252	)
Balance as of June 30, 2012	$	97,112

As of June 30, 2012 and December 31, 2011, $2.2 million and $2.4 million, respectively, of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

NOTE 8. LONG–TERM DEBT

Credit Facility

As of June 30, 2012, 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 assets and the assets of our subsidiaries. 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 total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.25 to 1.0. As of June 30, 2012, 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 3.58% at June 30, 2012).

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, 2012, the borrowing base under the facility was $750.0 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 $240.0 million and $660.0 million outstanding under the facility at June 30, 2012 and December 31, 2011, respectively.

8.0% Senior Notes due 2019

On March 13, 2012, we issued an additional $200.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019 (the “Additional Notes”) at an offering price equal to 103% of par, or $206.0 million, plus $6.6 million of accrued interest from October 15, 2011 pursuant to the same indenture under which our existing $300.0 million of 8.0% senior unsecured notes due 2019 (the “Existing Notes”) were issued. The Additional Notes and Existing Notes are treated as a single class of debt securities under the indenture. We received proceeds of $202.0 million after payment of $4.0 million of offering expenses. We used the proceeds to repay indebtedness under our credit facility.

Our senior notes due 2019 are 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 we nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

The aggregate carrying amount of our senior notes due 2019 was $499.2 million and $293.0 million at June 30, 2012 and December 31, 2011, respectively.

NOTE 9. 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, 2012 or December 31, 2011.

As of June 30, 2012, we expect our commitment to fund the construction activities for Cardinal and UEO to be between $35.0 million and $40.0 million for the remainder of 2012 and to be between $100.0 million and $115.0 million for 2013 and 2014.

NOTE 10. OWNERS’ EQUITY

Units Outstanding

At June 30, 2012, owners’ equity consists of 38,447,350 common units and 3,873,357 Class B units, collectively representing a 98% limited partnership interest in us, and a 2% general partnership interest.

Issuance of Units

In January 2012, we issued 0.2 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 $2.8 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.

In February 2012, we closed a public offering of 4.025 million common units at an offering price of $67.95 per common unit. We received proceeds of $267.9 million, including a contribution of $5.4 million by our general partner to maintain its 2% interest in us. We used the proceeds to repay indebtedness outstanding under our credit facility.

Cash Distributions

The following sets forth the distributions we paid during the six months ended June 30, 2012:

Date Paid	Period Covered	Distribution per Unit		Total Distribution
February 14, 2012	October 1, 2011 – December 31, 2011	$	0.763	$	29,815
May 15, 2012	January 1, 2012 – March 31, 2012		0.764		32,994
				$	62,809

On July 26, 2012, the board of directors of EV Management declared a $0.765 per unit distribution for the second quarter of 2012 on all common and Class B units. The distribution of $33.0 million is to be paid on August 14, 2012 to unitholders of record at the close of business on August 7, 2012.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 11. NET INCOME (LOSS) PER LIMITED PARTNER UNIT

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income	$	14,956		$	39,163		$	43,549		$	5,174
Less:
Incentive distribution rights		–			(2,945	)		–			(5,879	)
General partner’s 2% interest in net income		(299	)		(783	)		(871	)		(103	)
Limited partners’ interest in net income (loss)	$	14,657		$	35,435		$	42,678		$	(808	)

Weighted average limited partner units outstanding:
Common units		38,447			34,174			37,436			32,880
Class B units		3,873			–			3,873			–
Performance units ⁽¹⁾		132			120			137			122
Denominator for basic net income (loss) per limited partner unit		42,452			34,294			41,446			33,002
Dilutive phantom units ⁽²⁾		226			240			293			–
Denominator for diluted net income (loss) per limited partner unit		42,678			34,534			41,739			33,002

Net income (loss) per limited partner unit:
Basic	$	0.35		$	1.03		$	1.03		$	(0.02	)
Diluted	$	0.34		$	1.03		$	1.02		$	(0.02	)

⁽¹⁾

Our earned but unvested performance units are considered to be participating securities for purposes of calculating our net income (loss) per limited partner unit and, accordingly, are included in the basic computation as such.

⁽²⁾

Phantom units accounted for as equity awards totaling 0.5 million units were not included in the computation of diluted net income (loss) per limited partner unit because the effect would have been anti-dilutive for the six months ended June 30, 2011.

NOTE 12. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $3.3 million and $2.8 million in the three months ended June 30, 2012 and 2011, respectively, and $6.6 million and $5.5 million in the six months ended June 30, 2012 and 2011, 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 $4.1 million and $3.4 million in the three months ended June 30, 2012 and 2011, respectively, and $8.1 million and $7.2 million in the six months ended June 30, 2012 and 2011, 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.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 13. OTHER SUPPLEMENTAL INFORMATION

Supplemental cash flows and non–cash transactions were as follows:

	Six Months Ended June 30,
	2012			2011
Supplemental cash flows information:
Cash paid for interest	$	25,180	⁽¹⁾	$	5,595
Cash paid for income taxes		340			250

Non–cash transactions:
Costs for additions to oil and natural gas properties in accounts payable and accrued liabilities		15,310			5,241
Disbursement from escrow account for additions to oil and natural gas properties		7,477			–

⁽¹⁾

Includes the $6.6 million of accrued interest received in conjunction with our debt offering in March 2012 (see Note 8).

NOTE 14. 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 user of its financial statements to understand the effect of those arrangements on its financial position. The provisions of ASU 2011–11 are applicable to annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We will adopt ASU 2011–11 on January 1, 2013, and we have not yet determined the impact of this ASU on our unaudited condensed consolidated financial statements.

No other new accounting pronouncements issued or effective during the six months ended June 30, 2012 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

NOTE 15. SUBSEQUENT EVENT

In August 2012, we signed an agreement to acquire oil and natural gas assets for $83.2 million, subject to customary closing conditions and purchase price adjustments. The acquisition is expected to close in August 2012.

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, 2011.

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.

Our properties are 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, the Monroe Field in Louisiana, the Permian Basin, Central and East Texas (which includes the Austin Chalk area), and Michigan. As of December 31, 2011, we had estimated net proved reserves of 15.1 MMBbls of oil, 808.6 Bcf of natural gas and 40.9 MMBbls of natural gas liquids, or 1,144.4 Bcfe, and a standardized measure of $1,406.1 million.

We have grown our reserves and production substantially since the beginning of 2010. Since January 1, 2010, we have completed 12 acquisitions for an aggregate purchase price of $1.0 billion. The estimated net proved reserves at December 31, 2011 attributable to these acquisitions were 789 Bcfe, representing 69% of our December 31, 2011 net proved reserves on an Mcfe basis. These acquisitions also provided us a new core operating area in the Barnett Shale and significant growth in our Mid–Continent area and Appalachian Basin, including significant interests prospective for the Utica Shale in Ohio. These acquisitions increased the amount and percentage of our net proved reserves that are undeveloped, which will increase our capital expenditures to develop these reserves, primarily through drilling and completion activities.

RECENT DEVELOPMENTS

In February 2012 and March 2012, we, along with certain institutional partnerships managed by EnerVest, had additional closings on the oil and natural gas properties in the Barnett Shale that we acquired in December 2011. We acquired a 31.63% proportional interest in these properties for an aggregate purchase price of $36.5 million, subject to customary purchase price adjustments. In addition, we also received $0.7 million in net final purchase price settlements from our acquisitions of oil and natural gas properties in November 2011 and December 2011.

In March 2012, we issued an additional $200.0 million in aggregate principal amount of 8.0% senior unsecured notes due 2019 at an offering price equal to 103% of par, or $206.0 million, plus $6.6 million of accrued interest from October 15, 2011 pursuant to the same indenture under which our existing $300.0 million of 8.0% senior unsecured notes due 2019 were issued. We received proceeds of $202.0 million after payment of $4.0 million of offering expenses. We used the proceeds to repay indebtedness under our credit facility.

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 and natural gas prices are expected 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 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, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

In order to mitigate the impact of changes in oil and natural gas 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 oil and natural gas price volatility on our cash flows. By removing a portion of this price volatility on our future oil and natural gas production through December 2015, we have reduced, but not eliminated, the potential effects of changing oil and natural gas 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 oil and natural gas 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.

Current Low Natural Gas Prices

Natural gas prices continued to decline through May 2012, but began increasing in June 2012. However, prices are still not at the levels that they were in 2011.

We have hedged approximately 92% and 82% of our estimated natural gas production for the remainder of 2012 and 2013, respectively, at prices higher than those currently prevailing. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and natural gas properties or revise our development plans, which may cause certain of our undeveloped well location to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, distribute to our unitholders and service our debt obligations.

If low natural gas prices continue for an extended period of time, we may be unable to hedge additional natural gas production for 2014 and future years at favorable prices. This could cause us to change our development plans for our natural gas properties and shut–in natural gas production, and may result in an impairment in the value of our natural gas properties, a reduction in the borrowing base under our credit facility and reduce our cash available for distribution and for servicing our debt obligations.

Utica Shale

Primarily through acquisitions completed in 2009 and 2010, we held, as of June 30, 2012, approximately 150,000 net working interest acres and an approximate 2% average overriding royalty interest in approximately 880,000 gross acres in the state of 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, 2012, 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. As of July 2012, seven wells have been permitted and three wells in which we have an interest have been drilled and completed.

During the second half of 2012, we intend to pursue alternatives for the monetization of all or a portion 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 transaction or transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our efforts to monetize the Utica Shale properties, it may take longer to complete a transaction than we expect, or we may decide not to monetize all or a portion of the Utica Shale properties in this time frame.

RESULTS OF OPERATIONS

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011

Production data:
Oil (MBbls)		282		241		567		449
Natural gas liquids (MBbls)		403		272		826		542
Natural gas (MMcf)		10,722		6,999		20,985		14,003
Net production (MMcfe)		14,828		10,080		29,341		19,951
Average sales price per unit:
Oil (Bbl)	$	90.74	$	98.63	$	95.43	$	94.58
Natural gas liquids (Bbl)		34.48		54.80		40.59		51.45
Natural gas (Mcf)		2.18		4.20		2.48		4.10
Mcfe		4.23		6.76		4.76		6.40
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.68	$	1.78	$	1.82	$	1.77
Production taxes		0.17		0.31		0.20		0.29
Total		1.85		2.09		2.02		2.06
Asset retirement obligations accretion expense		0.08		0.10		0.08		0.10
Depreciation, depletion and amortization		1.91		1.83		1.81		1.80
General and administrative expenses		0.68		0.71		0.76		0.79

Three Months Ended June 30, 2012 Compared with the Three Months Ended June 30, 2011

Net income for the three months ended June 30, 2012 was $15.0 million compared with $39.2 million for the three months ended June 30, 2011. This change reflects (i) $6.0 million in lower revenues, (ii) $20.1 million in increased operating expenses, (iii) $11.2 million in higher impairment charges, (iv) $1.9 million in decreased non–cash changes in the fair value of our derivatives and (v) $4.5 million in higher interest expense, partially offset by $20.4 million in increased realized gains from our derivatives.

Oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2012 totaled $62.8 million, a decrease of $5.3 million compared with the three months ended June 30, 2011. This decrease was the result of $21.6 million from lower prices for oil, natural gas and natural gas liquids offset by $16.3 million from increased production.

Lease operating expenses for the three months ended June 30, 2012 increased $6.9 million compared with the three months ended June 30, 2011 as the result of $7.8 million related to our 2011 acquisitions and our expanded development drilling program and $0.5 million ($0.04 per Mcfe) associated with the sales of oil in tanks acquired in certain of our 2011 acquisitions offset by $1.4 million due to a lower unit cost per Mcfe for our acquisitions of oil and natural gas properties in the Barnett Shale. Lease operating expenses per Mcfe were $1.68 in the three months ended June 30, 2012 compared with $1.78 in the three months ended June 30, 2011.

Dry hole and exploration costs for the three months ended June 30, 2012 increased $1.2 million compared with the three months ended June 30, 2011 as a result of increased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin and the Barnett Shale.

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, 2012 decreased $0.6 million compared with the three months ended June 30, 2011 as the result of $1.4 million due to lower average realized prices offset by $0.8 million from increased production. Production taxes for the three months ended June 30, 2012 were $0.17 per Mcfe compared with $0.31 per Mcfe for the three months ended June 30, 2011.

Asset retirement obligations accretion expense for the three months ended June 30, 2012 increased $0.2 million compared with the three months ended June 30, 2011 primarily due to the oil and natural gas properties that we acquired in 2011. Asset retirement obligations accretion expense for the three months ended June 30, 2012 was $0.08 per Mcfe compared with $0.10 per Mcfe for the three months ended June 30, 2011.

Depreciation, depletion and amortization for the three months ended June 30, 2012 increased $10.0 million compared with the three months ended June 30, 2011 due to $9.1 million from higher production and $0.9 million from a higher average DD&A rate per unit. The higher average DD&A rate per unit reflects the change that decreased prices for oil, natural gas and natural gas liquids had on our reserves estimates. Depreciation, depletion and amortization for the three months ended June 30, 2012 was $1.91 per Mcfe compared with $1.83 per Mcfe for the three months ended June 30, 2011.

General and administrative expenses for the three months ended June 30, 2012 totaled $10.2 million, an increase of $3.0 million compared with the three months ended June 30, 2011. This increase is the result of $2.1 million of higher equity compensation costs, $0.5 million of higher fees paid to EnerVest under the omnibus agreement and $0.5 million of acquisition due diligence costs related to our acquisition of oil and natural gas properties in December 2011. General and administrative expenses were $0.68 per Mcfe in the three months ended June 30, 2012 compared with $0.71 per Mcfe in the three months ended June 30, 2011.

In the three months ended June 30, 2012, we incurred $0.1 million of leasehold impairment charges 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. In the three months ended June 30, 2011, we incurred impairment charges of $5.1 million to write down oil and natural gas properties to their fair value as determined using the mutually agreed upon selling price we received upon the sale of these oil and natural gas properties.

During the three months ended June 30, 2012 and 2011, we recorded cash settlements of $35.3 million and $10.9 million, respectively, in realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. Realized gains on derivatives, net for the three months ended June 30, 2012 and 2011 exclude $0.7 million and $1.4 million, respectively, related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives. In addition, realized gains on derivatives, net, for the three months ended June 30, 2011 also include $4.7 million related to the June 2011 termination of three of our interest rate swaps.

Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In the three months ended June 30, 2012, the fair value of our open derivative contracts increased from a net asset of $149.9 million at March 31, 2012 to a net asset of $164.7 million at June 30, 2012 due to the decline in future oil prices in the three months ended June 30, 2012. In the three months ended June 30, 2011, the fair value of our open derivatives increased from a net asset of $49.3 million at March 31, 2011 to a net asset of $70.0 million at June 30, 2011. Included in the fair value at March 31, 2012 and 2011 were net receivables of $0.7 million and $1.4 million, respectively, related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives in the three months ended June 30, 2012 and 2011. In addition, the fair value at March 31, 2011 also included a net payable of $4.7 million related to the June 2011 termination of three of our interest rate swaps.

Interest expense for the three months ended June 30, 2012 increased $4.5 million compared with the three months ended June 30, 2011 due to $4.3 million from a higher weighted average long–term debt balance and $0.2 million from a higher weighted average effective interest rate.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011

Net income for the six months ended June 30, 2012 was $43.5 million compared with $5.2 million for the six months ended June 30, 2011. This change reflects (i) $10.7 million in higher revenues, (ii) $31.0 million in increased realized gains on our derivatives and (iii) $62.8 million in increased non–cash changes in the fair value of our derivatives partially offset by (iv) $44.2 million of increased operating expenses, (v) $10.2 million of higher impairment charges and (vi) $10.4 million in higher interest expense.

Oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2012 totaled $139.6 million, an increase of $11.9 million compared with the six months ended June 30, 2011. This increase was the result of $40.1 million from higher production offset by $28.2 million from lower prices primarily for natural gas and natural gas liquids.

Lease operating expenses for the six months ended June 30, 2012 increased $18.1 million compared with the six months ended June 30, 2011 as the result of $16.5 million related to our 2011 acquisitions and our expanded development drilling program and $1.7 million ($0.06 per Mcfe) associated with the sales of oil in tanks acquired in certain of our 2011 acquisitions offset by $0.1 million due to a lower unit cost per Mcfe for our acquisitions of oil and natural gas properties in the Barnett Shale. Lease operating expenses per Mcfe were $1.82 in the six months ended June 30, 2012 compared with $1.77 in the six months ended June 30, 2011.

Dry hole and exploration costs for the six months ended June 30, 2012 increased $3.0 million compared with the six months ended June 30, 2011 as a result of increased seismic costs at certain of our oil and natural gas properties in the Appalachian Basin and the Barnett Shale.

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, were $5.8 million for both the six months ended June 30, 2012 and 2011 as the result of $1.8 million from lower average realized prices offset by $1.8 million from increased production. Production taxes for the six months ended June 30, 2012 were $0.20 per Mcfe compared with $0.29 per Mcfe for the six months ended June 30, 2011.

Asset retirement obligations accretion expense for the six months ended June 30, 2012 increased $0.5 million compared with the six months ended June 30, 2011 due to the oil and natural gas properties that we acquired in 2011. Asset retirement obligations accretion expense for the six months ended June 30, 2012 was $0.08 per Mcfe compared with $0.10 per Mcfe for the six months ended June 30, 2011.

Depreciation, depletion and amortization for the six months ended June 30, 2012 increased $17.0 million compared with the six months ended June 30, 2011 due to higher production. Depreciation, depletion and amortization for the six months ended June 30, 2012 was $1.81 per Mcfe compared with $1.80 per Mcfe for the six months ended June 30, 2011.

General and administrative expenses for the six months ended June 30, 2012 totaled $22.3 million, an increase of $6.5 million compared with the six months ended June 30, 2011. This increase is the result of (i) $4.2 million of higher equity compensation costs, (ii) $1.0 million of higher fees paid to EnerVest under the omnibus agreement due to an increase in operations from our acquisitions of oil and natural gas properties in 2011, (iii) $0.4 million of acquisition due diligence costs related to our acquisition of oil and natural gas properties in December 2011, and (iv) an overall increase in third party costs related to our significant growth. General and administrative expenses were $0.76 per Mcfe in the six months ended June 30, 2012 compared with $0.79 per Mcfe in the six months ended June 30, 2011.

In the six months ended June 30, 2012, we incurred $0.4 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. In the six months ended June 30, 2011, we incurred impairment charges of $6.7 million to write down oil and natural gas properties to their fair value as determined using the mutually agreed upon selling price we received upon the sale of these oil and natural gas properties.

During the six months ended June 30, 2012 and 2011, we recorded cash settlements of $60.1 million and $26.0 million, respectively, in realized gains on derivatives, net, as the contract prices for our derivatives exceeded the underlying market price for that period. Realized gains on derivatives, net for the six months ended June 30, 2012 and 2011 also exclude $1.3 million and $2.9 million, respectively, related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives. In addition, realized gains on derivatives, net, for the six months ended June 30, 2011 include $4.7 million related to the June 2011 termination of three of our interest rate swaps.

Unrealized gains (losses) on derivatives, net represent the change in the fair value of our open derivatives during the period. In the six months ended June 30, 2012, the fair value of our open derivative contracts increased from a net asset of $138.8 million at December 31, 2011 to a net asset of $164.7 million at June 30, 2012 due to the decline in future oil prices in the six months ended June 30, 2012. In the six months ended June 30, 2011, the fair value of our open derivatives decreased from a net asset of $103.9 million at December 31, 2010 to a net asset of $70.0 million at June 30, 2011. Included in the fair value at December 31, 2011 and 2010 were net receivables of $1.3 million and $2.9 million, respectively, related to the initial value of derivatives acquired in our December 2010 acquisition of oil and natural gas properties that have been relieved through the settlement of such derivatives in the six months ended June 30, 2012 and 2011. In addition, the fair value at December 31, 2010 also included a net payable of $4.7 million related to the June 2011 termination of three of our interest rate swaps.

Interest expense for the six months ended June 30, 2012 increased $10.4 million compared with the six months ended June 30, 2011 due to $7.6 million from a higher weighted average long–term debt balance and $2.8 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. For 2012, we believe that cash on hand, 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 earlier this year 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, 2012, 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, 2012, the borrowing base was $750.0 million, and we had $240.0 million outstanding.

In March 2012, we issued an additional $200.0 million in aggregate principal amount of our 8.0% senior notes due 2019 and received proceeds of $202.0 million. We used the proceeds to repay indebtedness outstanding under our credit facility. As of June 30, 2012, the aggregate carrying amount of the senior notes due 2019 was $499.2 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, 2012, we had $29.6 million of cash and short–term investments, which included $28.2 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.

Counterparty Exposure

At June 30, 2012, our open derivative contracts were in a net receivable position with a fair value of $164.7 million. 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, 2012, all of our counterparties have performed pursuant to their derivative contracts.

Cash Flows

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

	Six Months Ended June 30,
	2012			2011
Operating activities	$	113,040		$	80,130
Investing activities		(101,076	)		(25,681	)
Financing activities		(12,644	)		(51,184	)

Operating Activities

Cash flows from operating activities were $113.0 million and $80.1 million in the six months ended June 30, 2012 and 2011, respectively. The increase was primarily due to higher production from our acquisitions of oil and natural gas properties in 2011 and higher prices for oil, partially offset by lower prices for natural gas and natural gas liquids and higher operating expenses.

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, 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 investments 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.

During the six months ended June 30, 2011, we spent $1.0 million for the acquisition of oil and natural gas properties and $33.7 million for development of our oil and natural gas properties. In addition, we received $4.1 million in final purchase price settlements, $2.8 million from settlements of acquired derivatives and $1.2 million in proceeds from the sale of oil and natural gas properties.

Financing Activities

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.

During the six months ended June 30, 2011, we received proceeds of $147.1 million, after payment of offering costs of $0.3 million, from our public equity offering in March 2011, and we received contributions of $3.2 million from our general partner in order to maintain its 2% interest in us. We also received net proceeds of $291.6 million from our debt offering in March 2011, after deducting offering expenses of $0.9 million. We used the proceeds from these offerings to repay $431.5 million of borrowings outstanding under our credit facility. In addition, we paid distributions of $56.0 million to holders of our common units and our general partner and $5.3 million in loan costs related to our new $1.0 billion credit facility.

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;

our estimated net proved reserves 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 and natural gas;

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 oil and natural gas reserves;

cash flows and liquidity;

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

availability of drilling and production equipment;

marketing of oil and natural gas;

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 on Form 10–K for the year ended December 31, 2011. This document is available through our web site 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 and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, oil and natural gas 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 and natural gas commodity contracts to reduce our risk of changes in the prices of oil and natural gas. 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 and natural gas.

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, 2012, we have commodity contracts covering approximately 53% of our production attributable to our estimated net proved reserves from July 2012 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 oil and natural gas commodity contracts at June 30, 2012 was a net asset of $174.0 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 and basis swaps of approximately $56.7 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 six months ended June 30, 2012 would have increased by approximately $1.8 million. The fair value of our interest rate swaps at June 30, 2012 was a liability of $9.3 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 $3.4 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 June 30, 2012 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, 2012 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

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, 2011.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

+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

Pursuant to Rule 406T of Regulation S–T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability.

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: August 9, 2012	By:	/s/ MICHAEL E. MERCER
		Michael E. Mercer
		Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

+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

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