Harvest Oil & Gas Corp. - Quarter Report: 2008 March (Form 10-Q)

Unassociated Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2008

o	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 x 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 o

Accelerated filer x

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 x

As of May 5, 2008, the registrant had 11,881,939 common units outstanding.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)		2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
Item 3. Quantitative and Qualitative Disclosures About Market Risk		19
Item 4. Controls and Procedures		19

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		20
Item 1A. Risk Factors		20
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		20
Item 3. Defaults Upon Senior Securities		20
Item 4. Submission of Matters to a Vote of Security Holders		20
Item 5. Other Information		20
Item 6. Exhibits		20

Signatures		22

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EV Energy Partners, L.P.

Condensed Consolidated Balance Sheets

(In thousands, except number of units)

(Unaudited)

	March 31,			December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	18,056		$	10,220
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		20,746			18,658
Related party		3,230			3,656
Other		275			15
Derivative asset		-			1,762
Prepaid expenses and other current assets		445			594
Total current assets		42,752			34,905

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; March 31, 2008, $39,256; December 31, 2007, $30,724		567,560			570,398
Other property, net of accumulated depreciation and amortization; March 31, 2008, $251; December 31, 2007, $239		212			225
Other assets		1,945			2,013
Total assets	$	612,469		$	607,541

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	13,376		$	12,113
Deferred revenues		-			1,122
Derivative liability		39,580			5,232
Total current liabilities		52,956			18,467

Asset retirement obligations		19,649			19,463
Long-term debt		270,000			270,000
Share-based compensation liability		720			1,507
Long-term derivative liability		19,317			15,074

Commitments and contingencies

Owners’ equity:
Common unitholders - 11,881,939 units and 11,839,439 units issued and outstanding as of March 31, 2008 and December 31, 2007, respectively		257,639			282,676
Subordinated unitholders - 3,100,000 units issued and outstanding as of March 31, 2008 and December 31, 2007		(12,357	)		(5,488	)
General partner interest		3,006			4,245
Accumulated other comprehensive income		1,539			1,597
Total owners’ equity		249,827			283,030
Total liabilities and owners’ equity	$	612,469		$	607,541

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Operations

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended March 31,
	2008			2007
Revenues:
Oil, natural gas and natural gas liquids revenues	$	44,528		$	10,040
Gain on derivatives, net		58			747
Transportation and marketing-related revenues		3,171			1,220
Total revenues		47,757			12,007

Operating costs and expenses:
Lease operating expenses		9,162			2,306
Cost of purchased natural gas		2,612			1,109
Production taxes		2,022			373
Asset retirement obligations accretion expense		298			91
Depreciation, depletion and amortization		8,544			2,032
General and administrative expenses		3,453			1,602
Total operating costs and expenses		26,091			7,513

Operating income		21,666			4,494

Other expense, net:
Interest expense		(3,758	)		(943	)
Loss on mark-to-market derivatives, net		(42,576	)		(6,245	)
Other income, net		68			92
Total other expense, net		(46,266	)		(7,096	)

Loss before income taxes		(24,600	)		(2,602	)
Income taxes		(72	)		-
Net loss	$	(24,672	)	$	(2,602	)
General partner’s interest in net loss	$	(493	)	$	(52	)
Limited partners’ interest in net loss	$	(24,179	)	$	(2,550	)
Net loss per limited partner unit:
Common units (basic and diluted)	$	(1.61	)	$	(0.28	)
Subordinated units (basic and diluted)	$	(1.61	)	$	(0.28	)
Weighted average limited partner units outstanding:
Common units (basic and diluted)		11,875			5,938
Subordinated units (basic and diluted)		3,100			3,100

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2008			2007

Cash flows from operating activities:
Net loss	$	(24,672	)	$	(2,602	)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		298			91
Depreciation, depletion and amortization		8,544			2,032
Share-based compensation cost		475			196
Amortization of deferred loan costs		69			27
Unrealized loss on derivatives, net		40,294			7,695
Changes in operating assets and liabilities:
Accounts receivable		(1,921	)		1,020
Prepaid expenses and other current assets		148			117
Other assets		-			(285	)
Accounts payable and accrued liabilities		799			726
Deferred revenues		(1,122	)		-
Net cash flows provided by operating activities		22,912			9,017

Cash flows from investing activities:
Acquisition of oil and natural gas properties		-			(160,944	)
Development of oil and natural gas properties		(5,341	)		(1,897	)
Net cash flows used in investing activities		(5,341	)		(162,841	)

Cash flows from financing activities:
Debt borrowings		-			163,600
Repayment of debt borrowings		-			(96,500	)
Deferred loan costs		-			(153	)
Proceeds from private equity offering		-			100,000
Offering costs		-			(70	)
Distributions paid		(9,735	)		(3,100	)
Distributions related to acquisitions		-			(5,801	)
Net cash flows (used in) provided by financing activities		(9,735	)		157,976

Increase in cash and cash equivalents		7,836			4,152
Cash and cash equivalents - beginning of period		10,220			1,875
Cash and cash equivalents - end of period	$	18,056		$	6,027

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.

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, 2007.

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

NOTE 2. SHARE-BASED COMPENSATION

We account for our share-based compensation in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123 - Revised 2004, Share-Based Payment (“SFAS 123(R)”). As of March 31, 2008, we had 0.2 million phantom units outstanding, which are subject to graded vesting over a two or three year period. On satisfaction of the vesting requirement, the holders of the phantom units are entitled, at our discretion, to either common units or a cash payment equal to the current value of the units. We account for these phantom units as liability awards, and the fair value of the 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 the phantom units based on the proportionate amount of the requisite service period that has been rendered to date.

During the three months ended March 31, 2008 and 2007, we recognized compensation cost of $0.5 million and $0.2 million, respectively, related to our phantom units. These costs are included in “General and administrative expenses” in our condensed consolidated statement of operations.

During the three months ended March 31, 2008, 42,500 phantom units vested and were converted to common units at a fair value of $1.3 million.

As of March 31, 2008, there was $4.6 million of total unrecognized compensation cost related to nonvested phantom units which is expected to be recognized over a weighted average period of 2.3 years.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 3. ACQUISITIONS

In 2007, we completed the following acquisitions:

·	in January, we acquired natural gas properties in Michigan from an institutional partnership managed by EnerVest for $69.5 million, net of cash acquired;

·	in March, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.4 million;

·	in June, we acquired oil and natural gas properties in Central and East Texas from Anadarko Petroleum Corporation for $93.6 million;

·	in October, we acquired oil and natural gas properties in the Permian Basin from Plantation Operating, LLC, a company sponsored by investment funds formed by EnCap Investments, L.P. for $154.7 million; and

·	in December, we acquired oil and natural gas properties in the Appalachian Basin from an institutional partnership managed by EnerVest for $59.6 million.

The following table reflects pro forma revenues, net income and net income per limited partner unit as if these acquisitions had taken place at the beginning of the period presented. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.

	Three Months Ended March 31,
	2007
Revenues	$	40,699
Net income		5,383
Net income per limited partner unit:
Basic	$	0.58
Diluted	$	0.58

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 4. RISK MANAGEMENT

Our business activities expose us to risks associated with changes in the market price of oil and natural gas. As such, future earnings are subject to change due to changes in these market prices. We use derivative instruments to reduce our risk of changes in the prices of oil and natural gas. As of March 31, 2008, we had entered into derivative instruments with the following terms:

Period Covered	Index		Hedged Volume per Day		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls):
Swaps - 2008		WTI		1,206	$	72.46	$		$
Collar - 2008		WTI		125				62.00		73.95
Swaps - 2009		WTI		981		71.78
Collar - 2009		WTI		125				62.00		73.90
Swaps - 2010		WTI		1,000		71.16

Natural Gas (MMBtu):
Swaps - 2008		Dominion Appalachia		6,500		9.07
Swaps - 2009		Dominion Appalachia		4,400		8.79
Swaps - 2010		Dominion Appalachia		5,600		8.65
Swap - 2011		Dominion Appalachia		2,500		8.69
Swaps - 2008		NYMEX		4,000		8.85
Collars - 2008		NYMEX		6,000				7.67		10.25
Swaps - 2009		NYMEX		4,500		8.00
Collars - 2009		NYMEX		7,000				7.79		9.50
Swaps - 2010		NYMEX		7,500		8.44
Collar - 2010		NYMEX		1,500				7.50		10.00
Swap - 2011		NYMEX		5,000		8.47
Swaps - 2008		MICHCON_NB		3,500		8.16
Collar -2008		MICHCON_NB		2,000				8.00		9.55
Swaps - 2009		MICHCON_NB		5,000		8.27
Swap - 2010		MICHCON_NB		5,000		8.34
Swaps - 2008		HOUSTON SC		5,300		8.17
Swaps - 2009		HOUSTON SC		4,320		8.28
Collar - 2010		HOUSTON SC		3,500				7.25		9.55
Swap - 2008		EL PASO PERMIAN		3,000		7.23
Swap - 2009		EL PASO PERMIAN		2,500		7.93
Swap - 2010		EL PASO PERMIAN		2,500		7.68

At March 31, 2008, the fair value associated with these derivative instruments was a net liability of $58.9 million.

As of March 31, 2008, we had accumulated other comprehensive income (“AOCI”) of $1.5 million related to derivative instruments where we removed the hedge designation. During the three months ended March 31, 2008 and 2007, we reclassified $0.1 million and $0.7 million, respectively, from AOCI to “Gain on derivatives, net” and we anticipate that $1.5 million will be reclassified from AOCI during the next nine months.

During the three months ended March 31, 2008 and 2007, we recorded unrealized losses of $40.4 million and $8.4 million, respectively, on the change in fair value of our derivative instruments in “Loss on mark-to-market derivatives, net.” In addition, we recorded net realized (losses) gains of $(2.2) million and $2.2 million during the three months ended March 31, 2008 and 2007, respectively, related to settlements of our derivative instruments in “Loss on mark-to-market derivatives, net.”

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 5. ASSET RETIREMENT OBLIGATIONS

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, 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. 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, 2007	$	19,595
Accretion expense		298
Revisions in estimated cash flows		(112	)
Balance as of March 31, 2008	$	19,781

The current portion of our ARO is included in “Accounts payable and accrued liabilities” on our condensed consolidated balance sheet.

NOTE 6. LONG-TERM DEBT

As of March 31, 2007, our credit facility consists of a $500.0 million senior secured revolving credit facility that expires in October 2012. 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 $50.0 million of available borrowing capacity for letters of credit. The facility contains certain covenants which, among other things, require the maintenance of a current ratio (as defined in the facility) of greater than 1.00 and a ratio of total debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 4.0 to 1.0. As of March 31, 2008, we were in compliance with all of the facility 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 5.58% at March 31, 2008).

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. As of March 31, 2008, the borrowing base under the facility was $275.0 million. The borrowing base was increased to $325.0 million in April 2008. The borrowing base is subject to scheduled redeterminations on a semi-annual basis 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.

At March 31, 2008, we had $270.0 million outstanding under the facility.

NOTE 7. COMMITMENTS AND CONTINGENCIES

Litigation

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 consolidated financial statements.

Environmental Matters

Our past and present operations include activities which are subject to extensive domestic (including U.S. federal, state and local) environmental regulations with regard to air and water quality and other environmental matters. Our environmental procedures, policies and practices are designed to ensure compliance with existing laws and regulations and to minimize the possibility of significant environmental damage.

We expense environmental costs if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable. We did not incur any material environmental expenses during the three months ended March 31, 2008 or 2007. In addition, we had no accrual for environmental liabilities as of March 31, 2008 or December 31, 2007.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 8. OWNERS’ EQUITY

On January 29, 2008, the board of directors of EV Management declared a $0.60 per unit distribution for the fourth quarter of 2007 on all common and subordinated units. The distribution of $9.7 million was paid on February 14, 2008 to unitholders of record at the close of business on February 8, 2008.

On April 25, 2008, the board of directors of EV Management declared a $0.62 per unit distribution for the first quarter of 2008 on all common and subordinated units. The distribution of $10.1 million is to be paid on May 15, 2008 to unitholders of record at the close of business on May 8, 2008.

NOTE 9. COMPREHENSIVE LOSS

Comprehensive loss includes all changes in equity during a period except those resulting from investments by and distributions to owners. The components of our comprehensive loss, net of related tax, are as follows:

	Three Months Ended March 31,
	2008			2007
Net loss	$	(24,672	)	$	(2,602	)
Other comprehensive loss:
Reclassification adjustment into earnings		(58	)		(747	)
Comprehensive loss	$	(24,730	)	$	(3,349	)

NOTE 10. NET LOSS PER LIMITED PARTNER UNIT

We calculate net loss per limited partner unit in accordance with Emerging Issues Task Force 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128 (“EITF 03-06”). The computation of net loss per limited partner unit is based on the weighted average number of common and subordinated units outstanding during the period. Basic and diluted net loss per limited partner unit is determined by dividing net loss, after deducting the amount allocated to the general partner interest, by the weighted average number of outstanding limited partner units during the period.

The following sets forth the net loss allocation in accordance with EITF 03-06:

	Three Months Ended March 31,
	2008			2007
Net loss	$	(24,672	)	$	(2,602	)
Less general partner’s 2% interest in net loss		493			52
Net loss available for limited partners	$	(24,179	)	$	(2,550	)

Weighted average common units outstanding (basic and diluted)
Common units (basic and diluted)		11,875			5,938
Subordinated units (basic and diluted)		3,100			3,100

Net loss per limited partner unit (basic and diluted)	$	(1.61	)	$	(0.28	)

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 11. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $1.2 million and $0.4 million in the three months ended March 31, 2008 and 2007, respectively, in monthly administrative fees for providing us general and administrative services. These fees are included in general and administrative expenses in our condensed consolidated statement of operations.

On January 31, 2007, we acquired natural gas properties in Michigan for $69.5 million, net of cash acquired, from certain institutional partnerships managed by EnerVest, and on March 30, 2007, we acquired additional natural gas properties in the Monroe Field in Louisiana from an institutional partnership managed by EnerVest for $95.4 million (see Note 3).

We have entered into operating agreements with EnerVest whereby a 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. During the three months ended March 31, 2008 and 2007, we reimbursed EnerVest $2.2 million and $0.8 million, 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. These costs are included in lease operating expenses in our condensed consolidated statement 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. We believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market.

During the three months ended March 31, 2007, we sold $1.3 million of natural gas to EnerVest Monroe Marketing, Ltd. (“EnerVest Monroe Marketing”), a subsidiary of one of the EnerVest partnerships. On March 30, 2007, we acquired EnerVest Monroe Marketing in our acquisition of natural gas properties in the Monroe Field in Louisiana (see Note 3).

NOTE 12. OTHER SUPPLEMENTAL INFORMATION

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

	Three Months Ended March 31,
	2008		2007
Supplemental cash flows information:
Cash paid for interest	$	4,046	$	379
Cash paid for income taxes		-		-

Non-cash transactions:
Costs for development of oil and natural gas properties in accounts payable and accrued liabilities		464		(8	)

NOTE 13. NEW ACCOUNTING STANDARDS

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities.

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

·	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

·	Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

·	Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

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

				Fair Value Measurements at March 31, 2008 Using:
	Total Carrying Value			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivative instruments	$	(58,897	)	$	-	$	(58,897	)	$	-

Our derivative instruments consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. These derivative instruments are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

As the fair value of these derivative instruments 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 derivative instruments as Level 2.

We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We have elected not to apply the provisions of SFAS No. 159.

In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:

·	acquisition costs will generally be expensed as incurred;

·	noncontrolling interests will be valued at fair value at the date of acquisition; and

·	liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.

SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We will adopt SFAS No. 161 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In March 2008, the FASB issued Emerging Issues Task Force 07-04, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF 07-04”), to provide guidance as to how current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights. EITF 07-04 is effective for fiscal years beginning after December 15, 2008. We will adopt EITF 07-04 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

NOTE 14. SUBSEQUENT EVENT

In April 2008, we entered into a definitive purchase and sale agreement to acquire oil properties in South Central Texas for $18.0 million. The acquisition, which is expected to close by the end of May 2008, is subject to customary closing conditions and purchase price adjustments. We plan to finance the acquisition with borrowings under our credit facility.

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 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, 2007.

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.

In 2007, we completed the following acquisitions (collectively, the “2007 acquisitions”):

·	in January, we acquired natural gas properties in Michigan (the “Michigan acquisition”) from an institutional partnership managed by EnerVest for $69.5 million, net of cash acquired;

·	in March, we acquired additional natural gas properties in the Monroe Field in Louisiana (the “Monroe acquisition”) from an institutional partnership managed by EnerVest for $95.4 million;

·	in June, we acquired oil and natural gas properties in Central and East Texas from Anadarko Petroleum Corporation (the “Anadarko acquisition”) for $93.6 million;

·	in October, we acquired oil and natural gas properties in the Permian Basin from Plantation Operating, LLC, a company sponsored by investment funds formed by EnCap Investments, L.P. (the “Plantation acquisition”) for $154.7 million; and

·	in December, we acquired oil and natural gas properties in the Appalachian Basin (the “Appalachian acquisition”) from an institutional partnership managed by EnerVest for $59.6 million.

Our Assets

As of December 31, 2007, our properties were located in the Appalachian Basin (primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern Louisiana, Central and East Texas, the Permian Basin and the Mid-Continent areas in Oklahoma, Texas and Louisiana. Our oil and natural gas properties had estimated net proved reserves of 4.5 MMBbls of oil, 250.0 Bcf of natural gas and 8.7 MMBbls of natural gas liquids, or 329.6 Bcfe, and a standardized measure of $679.9 million.

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 and natural gas production;

·	our ability to hedge commodity prices;

·	the amount of oil and natural gas we produce; and

·	the level of our operating and administrative costs.

Oil and natural gas prices have been, and are expected to be, volatile. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of factors beyond our control. Factors affecting the price of oil include the lack of excess productive capacity, geopolitical activities, worldwide supply disruptions, worldwide economic conditions, 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 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.

As of March 31, 2008, we are a party to derivative agreements, and we intend to enter into derivative agreements in the future to reduce the impact of oil and natural gas price volatility on our cash flows. By removing a significant portion of our price volatility on our future oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods.

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, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on 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.

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of these goods and services. 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 on our ability to manage our overall cost structure.

RESULTS OF OPERATIONS

	Three Months Ended March 31,
	2008		2007
Production data:
Oil (MBbls)		93		31
Natural gas liquids (MBbls)		124		-
Natural gas (MMcf)		3,617		1,158
Net production (MMcfe)		4,916		1,346
Average sales price per unit:
Oil (Bbl)	$	95.63	$	54.53
Natural gas liquids (Bbl)		60.65		-
Natural gas (Mcf)		7.78		7.19
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.86	$	1.71
Production taxes		0.41		0.28
Total		2.27		1.99
Depreciation, depletion and amortization		1.74		1.51
General and administrative expenses		0.70		1.19

Revenues

Oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2008 totaled $44.5 million, an increase of $34.5 million compared with the three months ended March 31, 2007. This increase was primarily the result of (i) an increase of $31.8 million related to the oil and natural gas properties that we acquired in the 2007 acquisitions, (ii) an increase of $2.3 million related to increased prices for oil, natural gas liquids and natural gas and (iii) an increase of $0.4 million related to increased production.

Transportation and marketing-related revenues for the three months ended March 31, 2008 increased $2.0 million compared with the three months ended March 31, 2007 primarily due to transportation and marketing-related revenues from the Monroe acquisition.

Lease operating expenses for the three months ended March 31, 2008 increased $6.9 million compared with the three months ended March 31, 2007 primarily as the result the oil and natural gas properties that we acquired in the 2007 acquisitions. Lease operating expenses per Mcfe were $1.86 in the three months ended March 31, 2008 compared with $1.71 in the three months ended March 31, 2007. This increase is primarily the result of the 2007 acquisitions having lease operating expenses of $1.91 per Mcfe for the three months ended March 31, 2008.

The cost of purchased natural gas for the three months ended March 31, 2008 increased $1.5 million compared with the three months ended March 31, 2007 primarily due to costs from the Monroe acquisition.

Production taxes for the three months ended March 31, 2008 increased $1.6 million compared with the three months ended March 31, 2007 primarily as the result of production taxes associated with the oil and natural gas properties that we acquired in the 2007 acquisitions. Production taxes for the three months ended March 31, 2008 were $0.41 per Mcfe compared with $0.28 per Mcfe for the three months ended March 31, 2007. This increase is primarily the result of the 2007 acquisitions having production taxes of $0.45 per Mcfe for the three months ended March 31, 2008.

Depreciation, depletion and amortization for the three months ended March 31, 2008 increased $6.5 million compared with the three months ended March 31, 2007 primarily due to the oil and natural gas properties that we acquired in the 2007 acquisitions. Depreciation, depletion and amortization for the three months ended March 31, 2008 was $1.74 per Mcfe compared with $1.51 per Mcfe for the three months ended March 31, 2007. This increase is primarily due to the oil and natural gas properties that we acquired in the 2007 acquisitions having depreciation, depletion and amortization of $1.82 per Mcfe for the three months ended March 31, 2008.

General and administrative expenses for the three months ended March 31, 2008 totaled $3.5 million, an increase of $1.9 million compared with the three months ended March 31, 2007. This increase is primarily the result of (i) an increase of $0.8 million of fees paid to EnerVest under the omnibus agreement, (ii) an increase of $0.4 million in accounting costs, (iii) an increase of $0.4 million in compensation cost related to our phantom units and (iv) an overall increase in costs related to our significant growth. General and administrative expenses were $0.70 per Mcfe in the three months ended March 31, 2008 compared with $1.19 per Mcfe in the three months ended March 31, 2007.

Due to fluctuations in the commodity market, loss on mark-to-market derivatives, net for the three months ended March 31, 2008 included $2.2 million of net realized losses and $40.4 million of unrealized losses on the mark-to-market of derivatives.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity and capital have been issuances of equity 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 partners and working capital needs. For 2008, 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 and satisfy our short-term liquidity needs. We may also utilize various financing sources available to us, including the issuance of additional common units through public offerings or private placements, to fund our long-term liquidity needs. Our ability to complete future offerings of our common units and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

Available Credit Facility

We have a $500.0 million senior secured credit facility that expires in October 2012. 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 $50.0 million of available borrowing capacity for letters of credit. The facility contains certain covenants which, among other things, require 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 4.0 to 1.0. As of March 31, 2008, we were in compliance with all of the facility covenants.

Borrowings under the facility will 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. The amount of borrowings that we may have outstanding under the facility is subject to scheduled redeterminations on a semi-annual basis 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.

At March 31, 2008, we had $270.0 million outstanding under the facility.

Cash Flows

Cash flows provided by (used in) type of activity were as follows for the three months ended March 31, 2008 and 2007:

	Three Months Ended March 31,
	2008			2007
Operating activities	$	22,912		$	9,017
Investing activities		(5,341	)		(162,841	)
Financing activities		(9,735	)		157,976

Operating Activities

Cash flows from operating activities provided $22.9 million and $9.0 million in the three months ended March 31, 2008 and 2007, respectively. The increase reflects our significant growth as a result of the 2007 acquisitions.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. During the three months ended March 31, 2008, we spent $5.3 million for the development of our oil and natural gas properties. During the three months ended March 31, 2007, we spent $160.9 million for the Michigan acquisition and the Monroe acquisition and $1.9 million for the development of our oil and natural gas properties.

Financing Activities

During the three months ended March 31, 2008, we paid distributions of $9.7 million to our general partners and holders of our common and subordinated units.

During the three months ended March 31, 2007, we received net proceeds of $99.9 million from our private equity offering in February 2007. From these net proceeds, we repaid $96.5 million of borrowings outstanding under our credit facility. We borrowed $163.6 million under our credit facility to finance the Michigan acquisition and the Monroe acquisition and paid distributions of $3.1 million to our general partner and holders of our common and subordinated units. In addition, as we acquired oil and natural gas properties in the Michigan acquisition and the Monroe acquisition from institutional partnerships managed by EnerVest, we carried over the historical costs related to EnerVest’s interests and applied purchase accounting to the remaining interests and recorded deemed distributions of $5.8 million related to the difference between the purchase price allocations and the amounts paid for the Michigan acquisition and the Monroe acquisition.

NEW ACCOUNTING STANDARDS

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

·	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

·	Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

·	Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

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

				Fair Value Measurements at March 31, 2008 Using:
	Total Carrying Value			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivative instruments	$	(58,897	)	$	-	$	(58,897	)	$	-

We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

·	acquisition costs will generally be expensed as incurred;

·	noncontrolling interests will be valued at fair value at the date of acquisition; and

·	liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.

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 Securities Exchange Act of 1934, as amended, (each a “forward-looking statement”). 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.

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 our Annual Report on Form 10-K for the year ended December 31, 2007. 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.

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 financial instrument transactions to manage or reduce market risk, but do not enter into derivative financial instrument transactions for speculative purposes.

Commodity Price Risk

Our major market risk exposure is to oil and natural gas prices, which 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, energy financial instruments 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 physical oil and natural gas to protect their profit margins.

As of March 31, 2008, we had entered into derivative instruments for oil and natural gas with the following terms:

Period Covered	Index		Hedged Volume per Day		Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls):
Swaps - 2008		WTI		1,206	$	72.46	$		$
Collar - 2008		WTI		125				62.00		73.95
Swaps - 2009		WTI		981		71.78
Collar - 2009		WTI		125				62.00		73.90
Swaps - 2010		WTI		1,000		71.16

Natural Gas (MMBtu):
Swaps - 2008		Dominion Appalachia		6,500		9.07
Swaps - 2009		Dominion Appalachia		4,400		8.79
Swaps - 2010		Dominion Appalachia		5,600		8.65
Swap - 2011		Dominion Appalachia		2,500		8.69
Swaps - 2008		NYMEX		4,000		8.85
Collars - 2008		NYMEX		6,000				7.67		10.25
Swaps - 2009		NYMEX		4,500		8.00
Collars - 2009		NYMEX		7,000				7.79		9.50
Swaps - 2010		NYMEX		7,500		8.44
Collar - 2010		NYMEX		1,500				7.50		10.00
Swap - 2011		NYMEX		5,000		8.47
Swaps - 2008		MICHCON_NB		3,500		8.16
Collar -2008		MICHCON_NB		2,000				8.00		9.55
Swaps - 2009		MICHCON_NB		5,000		8.27
Swap - 2010		MICHCON_NB		5,000		8.34
Swaps - 2008		HOUSTON SC		5,300		8.17
Swaps - 2009		HOUSTON SC		4,320		8.28
Collar - 2010		HOUSTON SC		3,500				7.25		9.55
Swap - 2008		EL PASO PERMIAN		3,000		7.23
Swap - 2009		EL PASO PERMIAN		2,500		7.93
Swap - 2010		EL PASO PERMIAN		2,500		7.68

We do not designate these or future derivative agreements as hedges for accounting purposes pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Accordingly, the changes in the fair value of these agreements are recognized currently in earnings. At March 31, 2008, the fair value associated with these derivative instruments was a net liability of $58.9 million.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2008 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 Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

As of the date of this filing, there have been no significant changes from the risk factors previously disclosed in our “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.

An investment in our common units involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2007. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in us.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

________________

+ Filed herewith

SIGNATURES

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


	EV Energy Partners, L.P. (Registrant)

Date: May 9, 2008	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

________________

+ Filed herewith