Harvest Oil & Gas (HRST) 8-K EV Energy Partners Announces Over $200 Million in Acquisitions, Second Quarter 2008 Results, Anticipated Distribution Increase and Updated Guidance

EV Energy Partners Announces Over $200 Million in Acquisitions, Second Quarter 2008 Results, Anticipated Distribution Increase and Updated Guidance

HOUSTON, August 11, 2008 (BUSINESS WIRE) -- EV Energy Partners, L.P. (Nasdaq:EVEP) today announced that it had entered into agreements to acquire natural gas and oil properties for $202.7 million. EVEP also announced results for the second quarter 2008 and filed its Form 10-Q with the Securities and Exchange Commission. In addition, EVEP announced an anticipated distribution increase to $0.75 per common unit for the third quarter of 2008, payable during the fourth quarter of 2008, and provided updated guidance for the second half of 2008.

Acquisitions

EVEP has entered into four agreements to acquire natural gas and oil properties in the San Juan Basin, Mid-Continent (Oklahoma, Texas Panhandle and Kansas), Eastland County, Texas and West Virginia for $202.7 million. The acquisitions, which have been approved by the Board of Directors, are expected to close between the end of August and mid-September, and are subject to customary closing conditions and purchase price adjustments. The San Juan Basin assets are being acquired from institutional partnerships managed by EnerVest, Ltd., the West Virginia assets are being acquired from EnerVest, Ltd. and the Mid-Continent assets are being acquired from an EnCap sponsored company.

The properties to be acquired include:

― Over 440 producing wells

― Estimated proved reserves (based on recent strip prices) of approximately 88 Bcfe

― 58% natural gas, 18% oil and 24% natural gas liquids

― 94% proved developed producing

― High operating percentage and working/net revenue interests

― Reserves-to-production ratio of 18.7 years

― Current net daily production of approximately 12,900 Mcfe per day

	San Juan		Mid-Continent		Eastland Co.		West Virginia
Purchase Price ($mm)	142.1		38.8		16.0		5.8
Producing Wells	170		128		58		86
Proved Reserves (Bcfe) (1)	65.5		13.7		6.5		2.3
Proved Developed Producing %	95	%	100	%	72	%	99	%
Natural Gas / Oil / NGL %	58 / 10 / 32		78 / 22 / 0		2 / 90 / 8		100 / 0 / 0
Percentage Operated	84	%	100	%	100	%	75	%
Average Working Interest	77	%	67	%	100	%	84	%
Current Production (Mcfe per day)	9,100		2,800		600		390
Reserves-to-Production Ratio	19.7		13.7		29.7		16.2
(1) Based on recent strip prices.

EVEP plans to initially finance the acquisitions with borrowings under its amended and restated credit facility. EVEP has agreed with EnerVest that it will receive its share of the net proceeds, estimated to be approximately $35 million, in EVEP common units based on the volume weighted average price of the common units from August 7^th through August 14^th (the three trading days prior to and after today’s announcement). However, in order to receive common units, EnerVest must receive the consent of the investors in its institutional partnerships. If EnerVest does not receive the consent, only approximately $5 million of the estimated proceeds to EnerVest will be paid in common units, and the balance will be paid in cash.

John B. Walker, Chairman and CEO stated “We are very pleased with our ongoing ability to find attractive, synergistic acquisitions which, combined with our continued strong cash flow generation, has enabled us to provide our unit holders with significant unit distribution growth. After the closing of these acquisitions, EnerVest, its employees, EVEP management and its directors will have purchased units or received units in transactions approaching $50 million year-to-date. We believe in the long-term growth prospects for EVEP.”

For the fourth quarter of 2008, EVEP expects the following for the properties to be acquired:

Net Daily Production:
Natural gas (Mcf)	7,650 - 8,100
Crude oil (Bbls)	320 - 340
Natural gas liquids (Bbls)	450 - 490
Total (Mcfe)	12,330 - 13,080
Price Differentials vs. NYMEX:
Natural gas (% of NYMEX Natural Gas)	85% - 88%
Crude oil (% of NYMEX Crude Oil)	93% - 97%
Natural gas liquids (% of NYMEX Crude Oil)	50% - 60%
Lease operating expenses ($thous)	2,000 - 2,350
Production and other taxes (% of oil, gas and ngl revenues)	10.2% - 10.6%
Incremental general & administrative expense ($thous)	380 - 460

EVEP plans to hedge a significant part of the expected proved developed producing production from the acquisitions through 2012 prior to closing of the acquisitions and, to date, has entered into the following additional NYMEX oil and natural gas price swaps:

	Volume		Swap Price	Volume		Swap Price
	Bbl / day	$	per Bbl	Mcf / day	$	per Mcf
Sept - Dec 2008:	640	$	125.04
2009	650	$	123.09	3,000	$	9.08
2010	575	$	122.72	3,000	$	9.13
2011	330	$	114.30	1,500	$	8.93
2012	310	$	113.85	1,500	$	8.69

EVEP’s total commodity price hedge positions, after taking into account the new hedges detailed above, are presented in the Hedge Summary Table at the end of this release.

Second Quarter 2008 Results

Adjusted EBITDA for the quarter was $30.6 million, a 124% increase over the second quarter of 2007 and a 6% increase over the first quarter of 2008. Distributable Cash Flow for the quarter was $18.4 million, a 117% increase over the second quarter of 2007 and an 18% increase over the first quarter of 2008. Adjusted EBITDA and Distributable Cash Flow are described in the attached table under “Non-GAAP Measures”.

EVEP reported a net loss of $99.5 million, or ($6.51) per basic and diluted weighted average unit outstanding, for the second quarter of 2008. Included in this loss were $118.1 million of non-cash net unrealized losses on commodity derivatives, and $0.8 million of non-cash unit based compensation costs contained in general and administrative expenses. For the second quarter of 2007, net income was $12.0 million, or $0.93 per basic and diluted weighted average unit outstanding, which included $3.4 million of non-cash net unrealized gains on commodity derivatives and $0.3 million of non-cash costs contained in general and administrative expenses. For the first quarter of 2008, net loss was $24.7 million, or ($1.61) per basic and diluted weighted average unit outstanding, which included $40.3 million of non-cash net unrealized losses on commodity derivatives and $0.5 million of non-cash costs contained in general and administrative expenses.

The $118.1 million non-cash net unrealized loss on derivatives for the second quarter of 2008 was due to the significant increase in future oil and natural gas prices that occurred from March 31, 2008 to June 30, 2008 and the effect of such increased prices on EVEP’s commodity price hedges which extend through 2012. However, since June 30, 2008, energy commodity prices have declined. If oil and natural gas futures prices as of August 8, 2008 had been utilized, EVEP would have recorded a non-cash unrealized gain of approximately $8.7 million for the second quarter of 2008.

For the quarter ended June 30, 2008, EVEP produced 3.403 Bcf of natural gas, 97 MBbls of crude oil and 135 MBbls of natural gas liquids, or 4.80 Bcfe. This is a 104% increase over second quarter 2007 production of 2.35 Bcfe, primarily due to acquisitions made throughout 2007. Production decreased by 2% from the first quarter 2008 production of 4.91 Bcfe, primarily due to pipeline curtailments experienced in the Monroe field for part of the second quarter, which reduced daily production from the Monroe field during the period of curtailment by approximately 35%, or 3.3 mmcf per day. For the quarter, this affected production by approximately 0.17 Bcfe. These curtailments are currently expected to continue into the fourth quarter of 2008. However, during any periods of significant curtailment, EVEP is contractually entitled to receive payment from the purchaser for the amount of gas production curtailed, subject to the purchaser recouping such amounts out of a percentage of future production during periods when such production is not curtailed. Without this curtailment, production would have been approximately 4.96 Bcfe, or 54.5 mmcfe per day for the quarter.

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Anticipated Distribution Increase

Based on the announced acquisitions and continued strong cash flow generation, management anticipates that it will recommend to the Board of Directors a $0.05 increase in the quarterly distribution rate to $0.75 per unit beginning with the third quarter 2008 distribution, payable during the fourth quarter of 2008, and a further distribution increase for the fourth quarter 2008 distribution.

Updated Guidance

Updated guidance for the third and fourth quarters of 2008 is presented in the table below. This includes the Mid-Continent and Eastland County acquisitions from September 1, 2008 and the San Juan and West Virginia acquisitions from September 8, 2008. This guidance also includes the assumption that pipeline curtailments in the Monroe field of approximately 3.3 mmcf per day, net to EVEP, continue into November 2008. To the extent such curtailments end or decline, EVEP’s natural gas production guidance range would increase by such amounts.

	3rd Qtr 2008						4th Qtr 2008
Net Production:
Natural Gas (MMcf)		3,300		-	3,650			4,000		-	4,400
Crude Oil (MBbls)		105		-	115			123		-	135
Natural Gas Liquids (MBbls)		135		-	150			170		-	186
Total Mmcfe		4,740		-	5,240			5,758		-	6,326
Average Daily Production (Mmcfe/d)		51.5		-	57.0			62.6		-	68.8
Average Price Differential vs NYMEX
Natural Gas (% of NYMEX natural gas)		95	%	-	98	%		94	%	-	97	%
Crude Oil (% of NYMEX Crude Oil)		96	%	-	100	%		95	%	-	99	%
Natural Gas Liquids (% of NYMEX Crude Oil)		55	%	-	60	%		54	%	-	60	%
Transportation Margin (a)		470		-	530			470		-	530
Expenses:
Operating Expenses:
LOE and other		10,400		-	11,400			11,650		-	12,800
Production Taxes (as % of revenue)		4.7	%	-	5.1	%		5.6	%	-	6.0	%
General and administrative expense (b)		2,900		-	3,200			3,200		-	3,500
Capital Expenditure ( c)		11,000		-	13,000			8,500		-	10,000

(a) Represents estimated transportation and marketing-related revenues less cost of purchased natural gas.

(b) Excludes non-cash general and administrative expense, of which non-cash unit based compensation is a part.

(c) Represents estimates for drilling and related capital expenditures. Does not include any amounts for acquisitions of oil and gas properties.

Quarterly Report on Form 10-Q

EVEP’s financial statements and related footnotes are available on our second quarter 2008 Form 10-Q, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP web site at http://www.evenergypartners.com.

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Conference Call

As announced on August 6, 2008, EV Energy Partners, L.P. will host an investor conference call Tuesday, August 12, 2008, at 9:00am (Eastern Time). Investors interested in participating in the call may dial 303-262-2130 and ask for the EV Energy Partners call at least 5 minutes prior to the start time, or may listen live over the internet through the Investor Relations section of the EVEP web site at http://www.evenergypartners.com .

EV Energy Partners, L.P., is a master limited partnership engaged in acquiring, producing and developing oil and gas properties. More information about EVEP is available on the internet at http://www.evenergypartners.com .

(code #: EVEP/G)

This press release may include "forward-looking statements" as defined by the Securities and Exchange Commission. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by EVEP based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of EVEP, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for natural gas and oil, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the EVEP's reports filed with the Securities and Exchange Commission.

The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions at oil and gas prices in effect at the time of the estimate, without future escalation. We include in this press release an estimate of net proved reserves using strip prices, rather than prices at the time of the estimate, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available from us at www.evenergypartners.com or from the SEC at www.sec.gov.

Any forward-looking statement speaks only as of the date on which such statement is made and EVEP undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

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Operating Statistics
	Three Months Ended June 30,				Six Months Ended June 30,
		2008		2007		2008		2007
Production data:
Oil (MBbls)		97		32		190		63
Natural gas liquids (MBbls)		135		3		259		3
Natural gas (MMcf)		3,403		2,143		7,020		3,301
Net production (MMcfe)		4,797		2,352		9,712		3,698
Average sales price per unit (1):
Oil (Bbl)	$	121.72	$	60.93	$	108.97	$	57.77
Natural gas liquids (Bbl)		67.57		40.87		64.26		40.87
Natural gas (Mcf)		10.63		7.34		9.16		7.29
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.99	$	1.79	$	1.93	$	1.76
Production taxes		0.54		0.20		0.48		0.23
Total		2.53		1.99		2.41		1.99
Depreciation, depletion and amortization		1.63		1.49		1.68		1.50
General and administrative expense		0.74		0.91		0.72		1.01
(1) Prior to ($12.2) and $1.8 million of net hedge (losses) gains for the three months ended June 30, 2008 and June 30, 2007, respectively, and prior to ($14.4) and $4.0 million of net realized hedge (losses) gains for the six months ended June 30, 2008 and June 30, 2007, respectively.

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Balance Sheet
(in $ thousands)
		June 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	14,507		$	10,220
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		27,806			18,658
Related party		13,611			3,656
Other		12			15
Derivative asset		-			1,762
Prepaid expenses and other current assets		294			594
Total current assets		56,230			34,905
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; June 30, 2008, $47,056; December 31, 2007, $30,724		586,546			570,398
Other property, net of accumulated depreciation and amortization; June 30, 2008, $262; December 31, 2007, $239		201			225
Other assets		1,999			2,013
Total assets	$	644,976		$	607,541
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	15,678		$	12,113
Deferred revenues		2,517			1,122
Derivative liability		77,821			5,232
Total current liabilities		96,016			18,467
Asset retirement obligations		21,078			19,463
Long-term debt		287,000			270,000
Share–based compensation liability		1,506			1,507
Long–term derivative liability		99,811			15,074
Commitments and contingencies
Owners’ equity:
Common unitholders		172,943			282,676
Subordinated unitholders		(34,482	)		(5,488	)
General partner interest		169			4,245
Accumulated other comprehensive income		935			1,597
Total owners’ equity		139,565			283,030
Total liabilities and owners’ equity	$	644,976		$	607,541

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Results of Operations
(in $ thousands, except per unit data)
	Three Months Ended June 30,						Six Months Ended June 30,
		2008			2007			2008			2007
Revenues:
Oil, natural gas and natural gas liquids revenues	$	57,136		$	17,791		$	101,664		$	27,831
Gain on derivatives, net		604			947			662			1,694
Transportation and marketing–related revenues		3,309			4,400			6,480			5,620
Total revenues		61,049			23,138			108,806			35,145
Operating costs and expenses:
Lease operating expenses		9,552			4,215			18,714			6,521
Cost of purchased natural gas		2,803			3,777			5,415			4,886
Production taxes		2,606			479			4,628			852
Asset retirement obligations accretion expense		308			123			606			214
Depreciation, depletion and amortization		7,811			3,504			16,355			5,536
General and administrative expenses		3,571			2,129			7,024			3,731
Total operating costs and expenses		26,651			14,227			52,742			21,740
Operating income		34,398			8,911			56,064			13,405
Other (expense) income, net:
Interest expense		(3,069	)		(1,380	)		(6,827	)		(2,323	)
(Loss) gain on mark–to–market derivatives, net		(130,889	)		4,245			(173,465	)		(2,000	)
Other income, net		94			181			162			273
Total other (expense) income, net		(133,864	)		3,046			(180,130	)		(4,050	)
(Loss) income before income taxes		(99,466	)		11,957			(124,066	)		9,355
Income taxes		(58	)		-			(130	)		-
Net (loss) income		($ 99,524	)	$	11,957			($ 124,196	)	$	9,355
General partner’s interest in net (loss) income		($ 1,991	)	$	239			($ 2,484	)	$	187
Limited partners’ interest in net (loss) income		($ 97,533	)	$	11,718			($ 121,712	)	$	9,168
Net (loss) income per limited partner unit:
Common units (basic and diluted)		($ 6.51	)	$	0.93			($ 8.13	)	$	0.84
Subordinated units (basic and diluted)		($ 6.51	)	$	0.93			($ 8.13	)	$	0.84
Weighted average limited partner units outstanding:
Common units (basic and diluted)		11,882			9,554			11,879			7,756
Subordinated units (basic and diluted)		3,100			3,100			3,100			3,100

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Statement of Cash Flows
(in $ thousands)
		Six Months ended			Six Months ended
		June 30, 2008			June 30, 2007
Cash flows from operating activities:
Net (loss) income		($124,196	)	$	9,355
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense		606			214
Depreciation, depletion and amortization		16,355			5,536
Share–based compensation cost		1,261			498
Amortization of deferred loan costs		144			57
Unrealized loss on derivatives, net		158,425			4,304
Changes in operating assets and liabilities:
Accounts receivable		(19,099	)		353
Prepaid expenses and other current assets		300			462
Other Assets		(5	)		(285	)
Accounts payable and accrued liabilities		3,183			575
Deferred revenues		1,395			-
Net cash flows provided by operating activities		38,369			21,069
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(17,491	)		(258,935	)
Development of oil and natural gas properties		(13,597	)		(3,111	)
Net cash flows used in investing activities		(31,088	)		(262,046	)
Cash flows from financing activities:
Debt borrowings		17,000			243,350
Repayment of debt borrowings		-			(196,350	)
Deferred loan costs		(125	)		(153	)
Proceeds from private equity offering		-			220,000
Offering costs		-			(131	)
Distributions paid		(19,869	)		(8,512	)
Distributions related to acquisitions		-			(5,801	)
Net cash flows (used in) provided by financing activities		(2,994	)		252,403
Increase in cash and cash equivalents		4,287			11,426
Cash and cash equivalents – beginning of period		10,220			1,875
Cash and cash equivalents – end of period	$	14,507		$	13,301

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Non GAAP Measures

We define Adjusted EBITDA as net income (loss) plus interest expense (income), depreciation, depletion and amortization, accretion of asset retirement obligation, unrealized loss (gain) on derivatives, non-cash compensation and other expense, write-off of deferred financing costs, income tax provision, exploration expense and dry hole cost and impairment of unproved properties. Distributable Cash flow is defined as Adjusted EBITDA less interest expense, net, income taxes and estimated maintenance capital expenditures.

Adjusted EBITDA and Distributable Cash Flow are used by our management to provide additional information and metrics relative to the performance of our business, including (prior to the creation of any reserves) the cash available to pay distributions to our unitholders. These financial measures indicate to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA and Distributable Cash Flow are also quantitative standards used throughout the investment community with respect to performance of publicly-traded partnerships. Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and Distributable Cash Flow exclude some, but not all, items that effect net income and operating income and these measures may vary among companies. Therefore, our Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

Reconciliation of Net Loss to Adjusted EBITDA and Distributable Cash Flow
(in $ thousands)
	Three Months Ended June 30,						Six Months Ended June 30,
		2008			2007			2008			2007
Net (loss) income		($ 99,524	)	$	11,957			($ 124,196	)	$	9,355
Add:
Income taxes		58			-			130			-
Interest expense, net		2,989			1,170			6,678			2,048
Depreciation, depletion and amortization		7,811			3,504			16,355			5,536
Asset retirement obligation accretion expense		308			123			606			214
Non-cash losses (gains) on commodity derivatives		118,131			(3,391	)		158,425			4,304
Non-cash unit based compensation expense		786			302			1,261			498
Adjusted EBITDA		30,559			13,665			59,259			21,955
Less:
Interest expense, net		2,989			1,170			6,678			2,048
Income taxes		58			-			130			-
Estimated maintenance capital expenditures (1)	��	9,115			4,000			18,455			6,300
Distributable Cash Flow		18,397			8,495			33,996			13,607
(1) Estimated maintenance capital expenditures are those expenditures estimated to be necessary to maintain the production levels of our oil and gas properties over the long term and the operating capacity of our other assets over the long term.

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Hedge Summary Table (as of 08/11/2008)
		Swap		Swap		Collar		Collar		Collar
		Volume		Price		Volume		Floor		Ceiling
		(Mmmbtu/Mbbls)				(Mmmbtu/Mbbls)
Natural Gas:
3rd Qtr 2008
Dominion Appalachia		598	$	9.07
El Paso Permian		276	$	7.23
Houston Ship Channel		486	$	8.16
MichCon Citygate		322	$	8.16		184	$	8.00	$	9.55
NYMEX		368	$	8.85		92	$	7.50	$	9.65
NYMEX						184	$	7.50	$	9.70
NYMEX						184	$	8.00	$	11.30
NYMEX						92	$	7.50	$	9.85
4th Qtr 2008
Dominion Appalachia		598	$	9.07
El Paso Permian		276	$	7.23
Houston Ship Channel		472	$	8.16
MichCon Citygate		322	$	8.16		184	$	8.00	$	9.55
NYMEX		368	$	8.85		92	$	7.50	$	9.65
NYMEX						184	$	7.50	$	9.70
NYMEX						184	$	8.00	$	11.30
NYMEX						92	$	7.50	$	9.85
2009
Dominion Appalachia		1,606	$	8.79
El Paso Permian		913	$	7.93
Houston Ship Channel		1,577	$	8.29
MichCon Citygate		1,825	$	8.27
NYMEX		2,738	$	8.43
NYMEX						365	$	7.50	$	8.80
NYMEX						1,460	$	7.75	$	9.15
NYMEX						730	$	8.00	$	10.55
2010
Dominion Appalachia		2,044	$	8.65
El Paso Permian		913	$	7.68
Houston Ship Channel						1,278	$	7.25	$	9.55
MichCon Citygate		1,825	$	8.34
NYMEX		3,833	$	8.64
NYMEX						548	$	7.50	$	10.00
2011
Dominion Appalachia		913	$	8.69		1,095	$	9.00	$	12.15
El Paso Permian		913	$	9.30
Houston Ship Channel						1,278	$	8.25	$	11.65
MichCon Citygate						1,643	$	8.70	$	11.85
NYMEX		3,468	$	8.95
2012
Dominion Appalachia						1,830	$	8.95	$	11.45
El Paso Permian		732	$	9.21
Houston Ship Channel						1,098	$	8.25	$	11.10
MichCon Citygate						1,647	$	8.75	$	11.05
NYMEX		3,477	$	9.60
Crude Oil: (NYMEX)
3rd Qtr 2008		144.1	$	82.75		11.5	$	62.00	$	73.95
4th Qtr 2008		182.9	$	91.98		11.5	$	62.00	$	73.95
2009		649.9	$	93.10		45.6	$	62.00	$	73.90
2010		629.6	$	90.84
2011		175.2	$	109.38		401.5	$	110.00	$	166.45
2012		168.4	$	108.76		366.0	$	110.00	$	170.85
Interest Rate Swap Agreements:
		Notional		Fixed		Floating
		Amount		Rate		Rate
		(in $ mill)
July 2008 - June 2012	$	200		4.163	%	1 month LIBOR

SOURCE: EV Energy Partners, L.P.

EV Energy Partners, L.P., Houston

Michael E. Mercer, 713-651-1144

http://www.evenergypartners.com

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