Harvest Oil & Gas Corp. - FORM 8-K - EX-99.1

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8-K - Harvest Oil & Gas Corp.	v213438_8k.htm

EV Energy Partners Announces Full Year and Fourth Quarter 2010 Results, 2010 Year End Proved Reserves, 2011 Guidance and Updated Hedge Positions

HOUSTON, TX –(MARKET WIRE) – 03/01/11 — EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the full year and fourth quarter 2010, its year end 2010 proved reserves and the filing of its Form 10-K with the Securities and Exchange Commission. In addition, EVEP announced 2011 guidance and an update of its commodity hedge positions presented in the Hedge Summary Table at the end of this release.

Full Year 2010 Results

Adjusted EBITDAX and distributable cash flow for 2010 were $148.1 million and $94.2 million, increases of 12 percent and 24 percent, respectively, over 2009 primarily due to acquisitions made in 2010 as well as higher realized oil and natural gas prices. Adjusted EBITDAX and distributable cash flow are described in the attached table under "Non-GAAP Measures".

Production for 2010 was 19.5 Bcf of natural gas, 679 MBbls of oil and 728 MBbls of natural gas liquids, or 27.9 billion cubic feet equivalents (Bcfe). This represents a 15 percent increase over 2009 production of 24.2 Bcfe, primarily due to acquisitions in 2010.

For 2010, EVEP reported net income of $106.1 million. Included in net income were $3.0 million of non-cash net unrealized gains on commodity and interest rate derivatives and $5.0 million of non-cash costs contained in general and administrative expenses. Also contained in general and administrative expenses were approximately $1.4 million of due diligence and other transaction costs related to acquisitions completed during 2010. We also recognized a $40.7 million gain on sale of certain unproved acreage and a $2.5 million non-cash charge to lease operating expenses related to oil in tanks purchased in connection with the Appalachian Basin acquisition closed in March 2010. For 2009, EVEP reported net income of $1.4 million. Included in 2009 net income was $51.7 million of non-cash net unrealized losses on commodity and interest rate derivatives and $3.7 million of non-cash costs contained in general and administrative expenses.

Fourth Quarter 2010 Results

Adjusted EBITDAX for the fourth quarter of 2010 was $41.6 million, a 21 percent increase over the fourth quarter of 2009 and a 12 percent increase over the third quarter of 2010. Distributable cash flow for the fourth quarter of 2010 was $26.8 million, a 26 percent increase over the fourth quarter of 2009 and a 11 percent increase over the third quarter of 2010.

For the fourth quarter of 2010, EVEP produced 6.0 Bcf of natural gas, 202 MBbls of oil and 187 MBbls of natural gas liquids, or 8.3 Bcfe. This is a 34 percent increase over fourth quarter 2009 production of 6.2 Bcfe, primarily due to production from our 2010 Appalachian Basin and Mid-Continent region acquisitions. Production increased by 19 percent from third quarter 2010 production of 7.0 Bcfe, primarily due to production from our Mid-Continent region acquisition closed at the end of the third quarter of 2010.

EVEP reported a net loss of $14.5 million for the fourth quarter of 2010. However, included in net loss were $31.6 million of non-cash net unrealized losses on commodity and interest rate derivatives and $1.6 million of non-cash costs contained in general and administrative expenses. Also contained in general and administrative expenses were approximately $0.4 million of due diligence and other transaction costs related to our acquisitions completed during the quarter. For the fourth quarter of 2009, EVEP reported a net loss of $2.5 million which included $17.3 million of non-cash net unrealized losses on commodity and interest rate derivatives and $1.5 million of non-cash costs contained in general and administrative expenses.

The $31.6 million non-cash net unrealized loss on commodity and interest rate derivatives for the fourth quarter of 2010 was primarily due to the increase in future oil prices that occurred from September 30, 2010 to December 31, 2010 and the effect of such increased prices on the mark-to-market valuation of EVEP’s outstanding derivatives which extend through 2014.

John Walker, Chairman and CEO said, “We are pleased with our results for the quarter and for 2010. During the year we completed over $550 million of acquisitions, adding significantly to our Appalachian Basin and Mid-Continent region assets and establishing a new core area with our Barnett Shale acquisition. With these acquisitions, we increased our proved reserves over year-end 2009 by 124 percent, and at an attractive reserve replacement cost of $1.23 per mcfe. In addition, we are evaluating the potential of our acreage in the developing Utica/Point Pleasant play. EVEP has approximately 150,000 net held-by-production acres, primarily in Ohio, that could be prospective for the Utica/Point Pleasant and also owns overriding royalty interests on approximately 80,000 net acres. However, until horizontal wells have been drilled and tested this summer, it is not possible to properly assess the full potential of the play.”

Year End 2010 Estimated Net Proved Reserves

EVEP’s year end 2010 estimated net proved reserves were 817.3 Bcfe, a 123.5 percent increase over year end 2009 estimated net proved reserves, primarily due to acquisitions completed during 2010. Approximately 70.4 percent were natural gas, 9.5 percent were oil and 20.1 percent were natural gas liquids. In addition, 70.7 percent were categorized as proved developed. Our reserve replacement cost for 2010 was $1.23 per mcfe. Reserve replacement cost is our cost incurred in oil and natural gas property acquisition and development activities divided by the sum of extensions and discoveries, purchases of minerals in place, and revisions of previous estimates of our estimated net proved reserves.

At December 31, 2010, the present value of future net pre-tax cash flows discounted at 10 percent was $1,026.5 million and the standardized measure of our estimated net proved reserves was $1,020.2 million. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”), without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. The prices used in determining our estimated net proved reserves at December 31, 2010, were $79.43 per Bbl of oil and $4.37 per MMBtu of natural gas.

							Natural Gas
	Natural Gas		Crude Oil		NGL's		Equivalents
	(Bcf)		(MMBbls)		(MMBbls)		(Bcfe)
Barnett Shale		218.5		0.1		15.2		310.0
Appalachia		95.2		4.7		-		123.5
Mid-Continent		58.3		2.8		0.8		79.7
San Juan		43.1		1.3		3.8		73.8
Monroe		64.7		-		-		64.7
Permian		23.9		0.9		5.7		63.4
Central and East Texas		23.6		3.1		2.0		54.3
Michigan		47.9		-		-		47.9
Total Proved Reserves		575.2		12.9		27.5		817.3

Proved Developed Reserves		416.8		10.9		16.0		578.0

2011 Guidance

	1st Qtr 2011			2nd Qtr 2011
Net Production:
Natural Gas (MMcf)	6,900	-	7,350	7,200	-	7,900
Crude Oil (MBbls)	190	-	215	195	-	215
Natural Gas Liquids (MBbls)	260	-	290	285	-	315
Total Mmcfe	9,600	-	10,380	10,080	-	11,080

Average Daily Production (Mmcfe/d)	106.7	-	115.3	110.8	-	121.8

Average Price Differential vs NYMEX
Natural Gas (% of NYMEX Natural Gas)	92%	-	96%	92%	-	96%
Crude Oil (% of NYMEX Crude Oil)	92%	-	96%	92%	-	96%
Natural Gas Liquids (% of NYMEX Crude Oil)	44%	-	50%	44%	-	50%

Transportation Margin ($ thous) (a)	350	-	400	350	-	400

Expenses:
Operating Expenses:
LOE and other ($ thous)	15,850	-	17,450	16,350	-	18,150
Production Taxes (as % of revenue)	4.4%	-	4.8%	4.4%	-	4.8%

General and administrative expenses ($ thous) (b)	4,500	-	5,500	4,500	-	5,500

Capital Expenditures ($ thous) (c)	13,000	-	17,000	15,000	-	19,000

	3rd Qtr 2011			4th Qtr 2011
Net Production:
Natural Gas (MMcf)	7,450	-	8,250	7,650	-	8,450
Crude Oil (MBbls)	200	-	220	200	-	220
Natural Gas Liquids (MBbls)	295	-	335	300	-	340
Total Mmcfe	10,420	-	11,580	10,650	-	11,810

Average Daily Production (Mmcfe/d)	113.3	-	125.9	115.8	-	128.4

Average Price Differential vs NYMEX
Natural Gas (% of NYMEX Natural Gas)	92%	-	96%	92%	-	96%
Crude Oil (% of NYMEX Crude Oil)	92%	-	96%	92%	-	96%
Natural Gas Liquids (% of NYMEX Crude Oil)	44%	-	50%	44%	-	50%

Transportation Margin ($ thous) (a)	350	-	400	350	-	400

Expenses:
Operating Expenses:
LOE and other ($ thous)	16,350	-	18,150	16,350	-	18,150
Production Taxes (as % of revenue)	4.4%	-	4.8%	4.4%	-	4.8%

General and administrative expenses ($ thous) (b)	4,500	-	5,500	4,500	-	5,500

Capital Expenditures ($ thous) (c)	23,000	-	29,000	12,000	-	16,000

(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. Does not include any future acquisition related due diligence or transaction costs.

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

Annual Report on Form 10-K and Unitholders’ Schedule K-1

EVEP’s financial statements and related footnotes are available on our 2010 Form 10-K, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP web site at http://www.evenergypartners.com.

Also available for download on our website by March 11, 2011 will be unitholders’ Schedule K-1’s for the tax year 2010. For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at (800)-973-7551.

Conference Call

As announced on February 25, 2011, EV Energy Partners, L.P. will host an investor conference call on March 1, 2011, at 9:30 a.m. Eastern Time (8:30 a.m. Central). Investors interested in participating in the call may dial (480)-629-9722 (quote conference ID 4419691) at least 5 minutes prior to the start time, or may listen live over the internet through the investor relations section of the EVEP website at http://www.evenergypartners.com. Financial results will also be posted in the investor relations section on the website.

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.

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.

Operating Statistics

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2010		2009		2010		2009
Production data:
Oil (MBbls)		202		128		679		514
Natural gas liquids (MBbls)		187		188		728		768
Natural gas (MMcf)		5,958		4,288		19,486		16,519
Net production (MMcfe)		8,295		6,184		27,933		24,210
Average sales price per unit :
Oil (Bbl)	$	79.57	$	71.92	$	74.78	$	56.17
Natural gas liquids (Bbl)		46.54		41.09		42.64		31.08
Natural gas (Mcf)		3.75		4.15		4.30		3.71
Mcfe		5.69		5.61		5.93		4.71
Average unit cost per Mcfe:
Production costs:
Lease operating expenses	$	1.78	$	1.69	$	1.92	$	1.71
Production taxes		0.26		0.30		0.28		0.25
Total		2.04		1.99		2.20		1.96
Asset retirement obligations accretion expense		0.13		0.09		0.11		0.08
Depreciation, depletion and amortization		2.01		2.06		1.98		2.15
General and administrative expenses		0.81		0.92		0.83		0.77

Consolidated Balance Sheets

(in $ thousands)

	December 31, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	23,127		$	18,806
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		27,742			14,599
Related party		-			2,881
Other		441			1,034
Derivative asset		55,100			26,733
Other current assets		1,158			625
Total current assets		107,568			64,678

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2010, $176,897; December 31, 2009, $121,970		1,324,240			771,752
Other property, net of accumulated depreciation and amortization; December 31, 2010, $465; December 31, 2009, $319		1,567			742
Long-term derivative asset		51,497			68,549
Other assets		1,885			1,984
Total assets	$	1,486,757		$	907,705

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Third party	$	20,678		$	10,310
Related party		182			-
Derivative liability		1,943			1,543
Total current liabilities		22,803			11,853

Asset retirement obligations		67,175			42,533
Long-term debt		619,000			302,000
Other long-term liabilities		3,048			3,212
Long-term derivative liability		784			676

Commitments and contingencies

Owners’ equity
Common unitholders		779,327			548,160
General partner interest		(5,380	)		(729	)
Total owners' equity		773,947			547,431
Total liabilities and owners' equity	$	1,486,757		$	907,705

Consolidated Statements of Operations

(in $ thousands, except per unit data)

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2010			2009			2010			2009
Revenues:
Oil, natural gas and natural gas liquids revenues	$	47,184		$	34,705		$	165,738		$	114,066
Transportation and marketing-related revenues		1,228			1,445			5,780			7,846
Total revenues		48,412			36,150			171,518			121,912

Operating costs and expenses:
Lease operating expenses		14,795			10,420			53,736			41,495
Cost of purchased natural gas		906			1,078			4,353			4,509
Dry hole and exploration costs		182			0			417			-
Production taxes		2,191			1,840			7,867			5,983
Asset retirement obligations accretion expense		1,109			527			3,153			2,035
Depreciation, depletion and amortization		16,685			12,744			55,221			52,048
General and administrative expenses		6,750			5,686			23,313			18,556
Gain on sales of oil and natural gas properties		(39	)		0			(40,656	)		-
Total operating costs and expenses		42,579			32,295			107,404			124,626

Operating income (loss)		5,833			3,855			64,114			(2,714	)

Other (expense) income, net:
Realized gains on derivatives, net		13,871			13,783			49,042			68,984
Unrealized (losses) gains on derivatives, net		(31,572	)		(17,261	)		2,994			(51,665	)
Interest expense		(2,751	)		(2,412	)		(10,442	)		(12,321	)
Other income (expense), net		174			(309	)		628			(626	)
Total other (expense) income, net		(20,278	)		(6,199	)		42,222			4,372

(Loss) income before income taxes		(14,445	)		(2,344	)		106,336			1,658
Income taxes		(43	)		(127	)		(285	)		(248	)
Net (loss) income	$	(14,488	)	$	(2,471	)	$	106,051		$	1,410
General partner’s interest	$	2,338		$	1,941		$	11,938		$	7,040
Limited partners’ interest	$	(16,826	)	$	(4,412	)	$	94,113		$	(5,630	)
Net (loss) income per limited partner unit:
Basic	$	(0.55	)	$	(0.19	)	$	3.35		$	(0.29	)
Diluted	$	(0.55	)	$	(0.19	)	$	3.34		$	(0.29	)
Weighted average limited partner units outstanding:
Basic		30,630			23,583			28,095			19,302
Diluted		30,630			23,583			28,162			19,302

Distributions declared per unit	$	0.759		$	0.755		$	3.03		$	3.01

Consolidated Statements of Cash Flows

(in $ thousands)

	Twelve Months Ended			Twelve Months Ended
	December 31, 2010			December 31, 2009

Cash flows from operating activities:
Net income	$	106,051		$	1,410
Adjustments to reconcile net income to net cash flows provided by operating activities:
Dry hole costs		170			-
Asset retirement obligations accretion expense		3,153			2,035
Depreciation, depletion and amortization		55,221			52,048
Equity-based compensation		5,043			3,659
Gain on sales of oil and natural gas properties		(40,656	)		-
Unrealized (gains) losses on derivatives, net		(2,994	)		51,665
Amoritization of deferred loan costs		564			799
Other		(169	)		544
Changes in operating assets and liabilities:
Accounts receivable		(9,320	)		3,955
Other current assets		2,215			214
Accounts payable and accrued liabilities		4,514			(2,126	)
Deferred revenues		-			(4,120	)
Long-term liabilities		(734	)		-
Other, net		(705	)		(558	)
Net cash flows provided by operating activities		122,353			109,525

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(568,433	)		(39,646	)
Development of oil and natural gas properties		(26,525	)		(14,271	)
Proceeds from sales of oil and natural gas properties		44,399			-
Net cash flows used in investing activities		(550,559	)		(53,917	)

Cash flows from financing activities:
Long-term debt borrowings		543,000			20,000
Repayments of long-term debt borrowings		(226,000	)		(185,000	)
Proceeds from equity offerings		204,965			149,038
Offering costs		(306	)		(484	)
Loan costs incurred		(465	)		(44	)
Contributions from general partner		4,267			3,077
Distributions to partners		(92,934	)		(65,017	)
Net cash flows provided by (used in) financing activities		432,527			(78,430	)

Increase (decrease) in cash and cash equivalents		4,321			(22,822	)
Cash and cash equivalents – beginning of period		18,806			41,628
Cash and cash equivalents – end of period	$	23,127		$	18,806

Non GAAP Measures

We define Adjusted EBITDAX as net income (loss) plus income tax provision, interest expense, net, realized losses on interest rate swaps, depreciation, depletion and amortization, asset retirement obligation accretion expense, non-cash losses (gains) losses on derivatives, amortization of upfront premiums paid to enter into commodity price hedge agreements, non-cash equity compensation, (gain) on sales of oil and natural gas properties, write down of crude oil inventory, and dry hole and exploration costs. Distributable Cash Flow is defined as Adjusted EBITDAX less income tax provision, cash interest expense, net, realized (gains) losses on interest rate swaps, amortization of upfront premiums paid to enter into commodity price hedge agreements and estimated maintenance capital expenditures.

Adjusted EBITDAX 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 EBITDAX and Distributable Cash Flow are also quantitative standards used throughout the investment community with respect to performance of publicly-traded partnerships. Adjusted EBITDAX 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 EBITDAX 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 EBITDAX and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow

(in $ thousands)

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2010			2009			2010			2009

Net (loss) income	$	( 14,488	)	$	( 2,471	)	$	106,051		$	1,410
Add:
Income taxes		43			127			285			248
Interest expense, net		2,746			2,405			10,398			12,189
Realized losses on interest rate swaps		2,189			2,200			8,652			8,351
Depreciation, depletion and amortization		16,685			12,744			55,221			52,048
Asset retirement obligation accretion expense		1,109			527			3,153			2,035
Non-cash losses (gains) on commodity derivatives		31,572			17,261			(2,994	)		51,665
Amortization of premiums on derivatives		-			209			-			608
Non-cash equity compensation expense		1,629			1,462			5,043			3,659
(Gain) on sales of oil and natural gas properties		(39	)		-			(40,656	)		-
Non-cash charges related to oil in tanks from 2009 and 2010		-			-			2,542			-
Appalachian Basin acquisitions included in lease operating expense

Dry hole and exploration costs		182			-			417			-
Adjusted EBITDAX	$	41,628		$	34,464		$	148,112		$	132,213

Less:
Income taxes		43			127			285			248
Cash interest expense, net		2,596			2,268			9,834			11,390
Realized losses on interest rate swaps		2,189			2,200			8,652			8,351
Amortization of premiums on derivatives		-			209			-			608
Estimated maintenance capital expenditures (1)		10,037			8,348			35,167			35,360
Distributable Cash Flow	$	26,763		$	21,312		$	94,174		$	76,256

(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.

Summary of New Hedge Positions Since 09/30/2010 (as of February 28, 2011)

		Swap		Swap		Collar		Collar		Collar
Period	Index	Volume		Price		Volume		Floor		Ceiling
		(Mmmbtu/				(Mmmbtu/
		Mbbls)				Mbbls)
Natural Gas
1Q 2011	NYMEX		1,443.0	$	4.95		279.3	$	5.93	$	6.82
2Q 2011	NYMEX		1,231.5	$	5.02		282.4	$	5.93	$	6.82
3Q 2011	NYMEX		1,061.0	$	5.14		285.5	$	5.93	$	6.82
4Q 2011	NYMEX		877.0	$	5.26		285.5	$	5.93	$	6.82

2011	NGPL TX/OK						1,019.0	$	5.75	$	6.58

1H2012	NYMEX		1,820.0	$	5.02		846.8	$	6.22	$	6.70
	NYMEX						169.6	$	6.25	$	8.13
2H2012	NYMEX		1,288.0	$	5.07		856.2	$	6.22	$	6.70
	NYMEX						171.4	$	6.25	$	8.13

2013	NYMEX		13,322.5	$	5.26

Crude Oil
1Q 2011	WTI		39.9	$	90.37		16.7	$	88.00	$	95.33
2Q 2011	WTI		35.8	$	90.29		16.9	$	88.00	$	95.33
3Q 2011	WTI		29.3	$	90.12		17.1	$	88.00	$	95.33
4Q 2011	WTI		23.7	$	89.92		17.1	$	88.00	$	95.33

1Q 2012	WTI		95.6	$	95.58		22.6	$	82.50	$	100.00
2Q 2012	WTI		86.5	$	95.51		22.6	$	82.50	$	100.00
3Q 2012	WTI		82.8	$	95.24		22.9	$	82.50	$	100.00
4Q 2012	WTI		73.6	$	95.18		22.9	$	82.50	$	100.00

1Q 2013	WTI		126.0	$	94.85
2Q 2013	WTI		122.9	$	94.72
3Q 2013	WTI		119.6	$	94.70
4Q 2013	WTI		115.0	$	94.60

1 H2014	WTI		217.2	$	96.41
2 H2014	WTI		379.6	$	96.30

Ethane
1Q 2011	Mt. Belvieu (Non-TET)-OPIS		103.5	$	25.20
2Q 2011	Mt. Belvieu (Non-TET)-OPIS		100.1	$	22.16
3Q 2011	Mt. Belvieu (Non-TET)-OPIS		96.6	$	20.32
4Q 2011	Mt. Belvieu (Non-TET)-OPIS		92.0	$	19.79

Propane
1Q 2011	Mt. Belvieu (Non-TET)-OPIS		63.0	$	53.19
2Q 2011	Mt. Belvieu (Non-TET)-OPIS		59.2	$	49.20
3Q 2011	Mt. Belvieu (Non-TET)-OPIS		57.5	$	49.36
4Q 2011	Mt. Belvieu (Non-TET)-OPIS		55.2	$	50.20

Hedge Summary Table (as of February 28, 2011)

		Swap		Swap		Collar		Collar		Collar
Period	Index	Volume		Price		Volume		Floor		Ceiling
		(Mmmbtu/				(Mmmbtu/
		Mbbls)				Mbbls)
Natural Gas
1Q 2011	NYMEX		4,115.9	$	6.16		387.8	$	5.90	$	7.03
	Dominion Appalachia		225.0	$	8.69		270.0	$	9.00	$	12.15
	El Paso Permian		225.0	$	9.30
	Houston Ship Channel						315.0	$	8.25	$	11.65
	MichCon Citygate						405.0	$	8.70	$	11.85
	NGPL TX/OK						251.3	$	5.75	$	6.58

2Q 2011	NYMEX		3,934.2	$	6.25		392.1	$	5.90	$	7.03
	Dominion Appalachia		227.5	$	8.69		273.0	$	9.00	$	12.15
	El Paso Permian		227.5	$	9.30
	Houston Ship Channel						318.5	$	8.25	$	11.65
	MichCon Citygate						409.5	$	8.70	$	11.85
	NGPL TX/OK						254.1	$	5.75	$	6.58

3Q 2011	NYMEX		3,793.4	$	6.34		396.4	$	5.90	$	7.03
	Dominion Appalachia		230.0	$	8.69		276.0	$	9.00	$	12.15
	El Paso Permian		230.0	$	9.30
	Houston Ship Channel						322.0	$	8.25	$	11.65
	MichCon Citygate						414.0	$	8.70	$	11.85
	NGPL TX/OK						256.9	$	5.75	$	6.58

4Q 2011	NYMEX		3,609.4	$	6.43		396.4	$	5.90	$	7.03
	Dominion Appalachia		230.0	$	8.69		276.0	$	9.00	$	12.15
	El Paso Permian		230.0	$	9.30
	Houston Ship Channel						322.0	$	8.25	$	11.65
	MichCon Citygate						414.0	$	8.70	$	11.85
	NGPL TX/OK						256.9	$	5.75	$	6.58

1H 2012	NYMEX		7,025.2	$	6.64		1,016.3	$	6.22	$	6.94
	El Paso Permian		364.0	$	9.21
	Dominion Appalachia						910.0	$	8.95	$	11.45
	Houston Ship Channel						546.0	$	8.25	$	11.10
	MichCon Citygate						819.0	$	8.75	$	11.05

2H 2012	NYMEX		6,550.4	$	6.79		1,027.5	$	6.22	$	6.94
	El Paso Permian		368.0	$	9.21
	Dominion Appalachia						920.0	$	8.95	$	11.45
	Houston Ship Channel						552.0	$	8.25	$	11.10
	MichCon Citygate						828.0	$	8.75	$	11.05

2013	NYMEX		16,607.5	$	5.65
	El Paso Permian		1,095.0	$	6.77
	El Paso San Juan		1,095.0	$	6.66

Jan-Aug 2014	NYMEX		1,215.0	$	7.06

		Swap		Swap			Collar		Collar		Collar
Period	Index	Volume		Price			Volume		Floor		Ceiling
		(Mmmbtu/					(Mmmbtu/
		Mbbls)					Mbbls)
Crude Oil
1Q 2011	WTI		116.4	$	94.53			115.7	$	105.66	$	156.16
2Q 2011	WTI		113.1	$	94.68			117.0	$	105.66	$	156.16
3Q 2011	WTI		107.5	$	94.91			118.3	$	105.66	$	156.16
4Q 2011	WTI		102.0	$	95.12			118.3	$	105.66	$	156.16

1Q 2012	WTI		167.0	$	96.49			112.6	$	104.53	$	156.77
2Q 2012	WTI		157.9	$	96.50			113.9	$	104.53	$	156.77
3Q 2012	WTI		155.0	$	96.38			115.1	$	104.53	$	156.77
4Q 2012	WTI		145.8	$	96.43			115.1	$	104.53	$	156.77

1Q 2013	WTI		252.0	$	86.74
2Q 2013	WTI		250.3	$	86.53
3Q 2013	WTI		248.4	$	86.37
4Q 2013	WTI		243.8	$	86.17

1H 2014	WTI		452.5	$	89.52
2H 2014	WTI		444.7	$	94.33

Ethane
1Q 2011	Mt. Belvieu(Non-TET)-OPIS		103.5	$	25.20
2Q 2011	Mt. Belvieu(Non-TET)-OPIS		100.1	$	22.16
3Q 2011	Mt. Belvieu(Non-TET)-OPIS		96.6	$	20.32
4Q 2011	Mt. Belvieu(Non-TET)-OPIS		92.0	$	19.79

Propane
1Q 2011	Mt. Belvieu(Non-TET)-OPIS		63.0	$	53.19
2Q 2011	Mt. Belvieu(Non-TET)-OPIS		59.2	$	49.20
3Q 2011	Mt. Belvieu(Non-TET)-OPIS		57.5	$	49.36
4Q 2011	Mt. Belvieu(Non-TET)-OPIS		55.2	$	50.20

		Notional		Fixed
		Amount		Rate
Interest Rate Swap Agreements		(in $ mill)
January 2011 - July 2012			200.0		4.163	%
January 2011 - Sept 2012			40.0		2.145	%

		Swap		Swap
		Volume		Price
Basis Swaps		(Mmmbtu/ Mbbls)
Discount (Premium) to NYMEX
2011	Dominion Appalachia		346.0	$	0.1975
2011	Columbia Appalachia		94.5	$	0.1500

EV Energy Partners, L.P., Houston

Michael E. Mercer, 713-651-1144

http://www.evenergypartners.com

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