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

Attached files

file	filename
8-K - FORM 8-K - Harvest Oil & Gas Corp.	v240513_8-k.htm
EX-99.2 - EXHIBIT 99.2 - Harvest Oil & Gas Corp.	v240513_ex99-2.htm

EV Energy Partners Announces Third Quarter 2011 Results and Updated Fourth Quarter 2011 Guidance and Commodity Hedge Positions

HOUSTON, TX – November 8, 2011 -- (MARKETWIRE) -- EV Energy Partners, L.P. (Nasdaq:EVEP) today announced results for the third quarter 2011 and filed its Form 10-Q with the Securities and Exchange Commission. In addition, EVEP announced updated guidance for the fourth quarter of 2011 and provided a summary of commodity price hedges entered into since its second quarter 2011 earnings release.

Third Quarter 2011 Results

Adjusted EBITDAX for the quarter was $52.2 million, a 40 percent increase over the third quarter of 2010 and a 5 percent decrease versus the second quarter of 2011. Distributable Cash Flow for the quarter was $30.8 million, a 28 percent increase over the third quarter of 2010 and a 7 percent decrease versus the second quarter of 2011. The changes in Adjusted EBITDAX and Distributable Cash Flow, which are described in the attached table under “Non-GAAP Measures,” are primarily attributable to the decrease in crude oil sales volumes and an increase in lease operating expenses, partially offset by an increase in natural gas and natural gas liquids production.

For the quarter ended September 30, 2011, EVEP produced 7.1 Bcf of natural gas, 207 MBbls of crude oil and 285 MBbls of natural gas liquids, or 10.1 Bcfe. This represents a 45 percent increase from the third quarter 2010 production of 7.0 Bcfe, primarily due to acquisitions completed during the fourth of 2010, and is essentially flat to the 10.1 Bcfe produced in the second quarter 2011.

EVEP reported net income of $87.8 million, or $2.42 and $2.40 per basic and diluted weighted average limited partner unit outstanding, respectively, for the third quarter of 2011. Included in net income were $68.8 million of non-cash net unrealized gains on commodity and interest rate derivatives and $2.7 million of non-cash costs contained in general and administrative expenses. General and administrative expenses also included $0.2 million of acquisition-related due diligence and other related transaction costs. Also included in net income was a $1.3 million non-cash realized loss on derivatives related to derivatives acquired in conjunction with a 2010 property acquisition. For the third quarter of 2010, net income was $58.1 million, or $1.88 and $1.87 per basic and diluted weighted average limited partner unit outstanding, which included $4.1 million of non-cash net unrealized gains on commodity and interest rate derivatives and $1.3 million of non-cash costs contained in general and administrative expenses. Also included in net income was a $36.8 million gain on sale of certain unproved acreage. For the second quarter of 2011, net income was $39.2 million, or $1.03 per basic and diluted weighted average limited partner unit outstanding. Included in net income were $17.4 million of non-cash net unrealized gains on commodity and interest rate derivatives and $1.7 million of non-cash costs contained in general and administrative expenses. General and administrative expenses also included $0.2 million of acquisition-related due diligence and other related transaction costs. Also included in net income was a $5.1 million impairment charge relating to a divestiture of non-core oil and natural gas properties and a $3.3 million non-cash realized gain on derivatives related to term extensions on certain interest rate swaps and to derivatives acquired in conjunction with a 2010 property acquisition.

The $68.8 million non-cash net unrealized gain on derivatives for the third quarter of 2011 was primarily due to the decrease in future oil prices that occurred from June 30, 2011, to September 30, 2011, and the effect of such decreased prices on the mark-to-market valuation of EVEP’s outstanding commodity derivatives.

John Walker, Chairman and CEO, said,”We are very pleased with the almost $500 million of accretive acquisitions that we recently announced in our core areas of operations. We are also pleased with the continuing positive developments in the Utica Shale and the steady performance in our existing asset base.”

Updated Fourth Quarter 2011 Guidance

The following table presents updated guidance for the fourth quarter of 2011, including the previously announced Mid-Continent area, Ohio and Barnett Shale bolt-on acquisitions that were recently completed and the two Barnett Shale acquisitions that are expected to close prior to year-end 2011.

	4th Qtr 2011
Net Production:
Natural Gas (MMcf)	7,650	-	8,450
Crude Oil (MBbls)	245	-	275
Natural Gas Liquids (MBbls)	285	-	315
Total Mmcfe	10,830	-	11,990

Average Daily Production (Mmcfe/d)	117.7	-	130.3

Average Price Differential vs NYMEX
Natural Gas (% of NYMEX Natural Gas)	96%	-	100%
Crude Oil (% of NYMEX Crude Oil)	93%	-	97%
Natural Gas Liquids (% of NYMEX Crude Oil)	55%	-	65%

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

Expenses:
Operating Expenses:
LOE and other ($ thous)	19,800	-	21,400
Production Taxes (as % of revenue)	4.2%	-	4.6%

General and administrative expense ($ thous) (b)	5,000	-	5,800

(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, also excludes any amounts for future acquisition related due diligence and transaction costs.

New Commodity Price Hedge Positions

Since its second quarter earnings release dated August 10, 2011, EVEP has entered into the following additional natural gas and crude oil hedge positions.

		Swap	Swap
Period	Index	Volume	Price
		(Mmmbtu /Mbbls)
Natural Gas
Nov-Dec 2011	NYMEX	115.9	$3.91
2012	NYMEX	732.0	$4.29
2013	NYMEX	657.0	$4.81
2014	NYMEX	584.0	$5.14
2015	NYMEX	547.5	$5.38

Crude
Nov-Dec 2011	WTI	18.3	$82.40
2012	WTI	128.1	$84.15
2013	WTI	118.6	$85.90
2014	WTI	109.5	$87.05

EVEP’s financial statements and related footnotes are available on our third quarter 2011 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.

Conference Call

As announced on November 2, 2011, EV Energy Partners, L.P. will host an investor conference call Wednesday, November 9, 2011 at 10 a.m. EST. Investors interested in participating in the call may dial 480-629-9866 (quote conference ID 4486338) at least five 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 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 September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Production data:
Oil (MBbls)		207		179		656		477
Natural gas liquids (MBbls)		285		181		827		541
Natural gas (MMcf)		7,141		4,809		21,144		13,528
Net production (MMcfe)		10,091		6,973		30,043		19,638
Average sales price per unit: (1)
Oil (Bbl)	$	84.76	$	71.11	$	91.48	$	72.75
Natural gas liquids (Bbl)		55.16		38.06		52.73		41.29
Natural gas (Mcf)		4.16		4.34		4.12		4.55
Mcfe		6.24		5.81		6.35		6.04
Average unit cost per Mcfe:
Production costs:
Lease operating expenses (2)	$	1.91	$	1.81	$	1.82	$	1.98
Production taxes		0.26		0.27		0.28		0.29
Total		2.17		2.08		2.10		2.27
Asset retirement obligations accretion expense		0.09		0.11		0.10		0.10
Depreciation, depletion and amortization		1.81		1.87		1.81		1.96
General and administrative expenses		0.81		0.86		0.79		0.84

(1) Prior to $16.3 and $15.5 million of net hedge gains and settlements on commodity derivatives for the three months ended September 30, 2011 and September 30, 2010, respectively and $46.3 and $41.6 million for the nine months ended September 30, 2011 and September 30, 2010, respectively.

(2) Lease operating expenses for the nine months ended September 30, 2010 include $2.5 million or $0.13 per mcfe of non-cash inventory write down charges.

Condensed Consolidated Balance Sheets (Unaudited)
(In $ thousands, except number of units)

	September 30, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	17,334		$	23,127
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		34,383			27,742
Related party		3,718			-
Other		852			441
Derivative asset		80,285			55,100
Other current assets		1,468			1,158
Total current assets		138,040			107,568

Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2011, $228,214; December 31, 2010, $176,897		1,342,636			1,324,240
Other property, net of accumulated depreciation and amortization;
September 30, 2011, $663; December 31, 2010, $465		1,381			1,567
Long-term derivative asset		57,280			51,497
Other assets		15,035			1,885
Total assets	$	1,554,372		$	1,486,757


LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Third party	$	38,981		$	20,678
Related party		-			182
Derivative liability		-			1,943
Total current liabilities		38,981			22,803

Asset retirement obligations		70,715			67,175
Long-term debt		505,351			619,000
Long-term liabilities		2,058			3,048
Long-term derivative liability		-			784

Commitments and contingencies

Owners’ equity:
Common unitholders - 34,173,650 units and 30,510,313 units
issued and outstanding as of September 30, 2011 and December 31, 2010, respectively		949,531			779,327
General partner interest		(12,264	)		(5,380	)
Total owners' equity		937,267			773,947
Total liabilities and owners' equity	$	1,554,372		$	1,486,757

Condensed Consolidated Statements of Operations (Unaudited)

(In $ thousands, except per unit data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues:
Oil, natural gas and natural gas liquids revenues	$	62,961		$	40,527		$	190,691		$	118,554
Transportation and marketing–related revenues		1,428			1,498			4,313			4,552
Total revenues		64,389			42,025			195,004			123,106

Operating costs and expenses:
Lease operating expenses		19,284			12,640			54,595			38,941
Cost of purchased natural gas		1,072			1,132			3,242			3,447
Dry hole and exploration costs		768			235			1,612			235
Production taxes		2,645			1,876			8,415			5,676
Asset retirement obligations accretion expense		920			770			2,856			2,044
Depreciation, depletion and amortization		18,225			13,016			54,232			38,536
General and administrative expenses		8,126			6,014			23,851			16,563
Impairment of oil and natural gas properties		(48	)		-			6,618			-
Gain on sale of oil and natural gas properties		-			(36,793	)		-			(40,617	)
Total operating costs and expenses		50,992			(1,110	)		155,421			64,825

Operating income		13,397			43,135			39,583			58,281

Other income (expense), net:
Realized gains on derivatives, net		13,914			13,305			41,698			35,171
Unrealized gains on derivatives, net		68,845			4,064			33,212			34,566
Interest expense		(8,172	)		(2,319	)		(21,455	)		(7,691	)
Other (expense) income, net		(125	)		61			108			454
Total other income, net		74,462			15,111			53,563			62,500

Income before income taxes		87,859			58,246			93,146			120,781
Income taxes		(51	)		(111	)		(164	)		(242	)
Net income	$	87,808		$	58,135		$	92,982		$	120,539
General partner’s interest in net income, including
incentive distribution rights	$	4,711		$	3,764		$	10,693		$	9,600
Limited partners’ interest in net income	$	83,097		$	54,371		$	82,289		$	110,939

Net income per limited partner unit:
Basic	$	2.42		$	1.88		$	2.46		$	4.07
Diluted	$	2.40		$	1.87		$	2.44		$	4.06

Weighted average limited partner units outstanding:
Basic		34,317			28,935			33,445			27,257
Diluted		34,623			29,025			33,710			27,309

Distributions declared per unit	$	0.762		$	0.758		$	2.283		$	2.271

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In $ thousands)

	Nine Months Ended September 30,
	2011			2010
Cash flows from operating activities:
Net Income	$	92,982		$	120,539
Adjustments to reconcile net income to net cash flows
provided by operating activities:
Asset retirement obligations accretion expense		2,856			2,044
Depreciation, depletion and amortization		54,232			38,536
Equity-based compensation cost		6,613			3,414
Impairment of oil and natural gas properties		6,618			-
Gain on sale of oil and natural gas properties		-			(40,617	)
Non-cash derivative activity		(37,893	)		(34,566	)
Amortization of discount on long-term debt		351			-
Amortization of deferred loan costs		914			413
Other, net		219			31
Changes in operating assets and liabilities:
Accounts receivable		(7,935	)		(5,028	)
Other current assets		(308	)		2,514
Accounts payable and accrued liabilities		15,952			2,649
Long-term liabilities		-			(734	)
Other, net		(600	)		(229	)
Net cash flows provided by operating activities		134,001			88,966

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(35,647	)		(267,683	)
Development of oil and natural gas properties		(52,936	)		(16,219	)
Deposit on acquisition of oil and natural gas properties		(7,700	)		-
Proceeds from sale of oil and natural gas properties		9,666			25,120
Settlements from acquired derivatives		4,443			-
Net cash flows used in investing activities		(82,174	)		(258,782	)

Cash flows from financing activities:
Long-term debt borrowings		30,000			258,000
Repayment of long-term debt borrowings		(436,500	)		(226,000	)
Proceeds from debt offering		292,500			-
Loan costs incurred		(6,355	)		(8	)
Proceeds from public equity offering		147,108			204,965
Offering costs		(333	)		(277	)
Contributions from general partner		3,191			4,267
Distributions paid		(85,514	)		(66,681	)
Distributions related to acquisition		(1,717	)		-
Net cash flows (used in) provided by financing activities		(57,620	)		174,266

(Decrease) increase in cash and cash equivalents		(5,793	)		4,450
Cash and cash equivalents – beginning of period		23,127			18,806
Cash and cash equivalents – end of period	$	17,334		$	23,256

Non-GAAP Measures

We define Adjusted EBITDAX as net income plus income tax provision, interest expense, net, realized losses on interest rate swaps, depreciation, depletion and amortization, asset retirement obligation accretion expense, non-cash realized losses (gains) on derivatives, non-cash unrealized gains on derivatives, non-cash equity compensation, impairment of oil and natural gas properties, gain on sale 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 losses on interest rate swaps and estimated maintenance capital expenditures.

Adjusted EBITDAX and Distributable Cash Flow are used by our management to provide additional information and statistics 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 affect 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 EBITDAX and Distributable Cash Flow

(In $ thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

Net income	$	87,808		$	58,135		$	92,982		$	120,539
Add:
Income taxes		51			111			164			242
Interest expense, net		8,168			2,312			21,441			7,652
Realized losses on interest rate swaps		1,108			2,162			5,075			6,463
Depreciation, depletion and amortization		18,225			13,016			54,232			38,536
Asset retirement obligation accretion expense		920			770			2,856			2,044
Non-cash realized losses (gains) on derivatives		1,299			-			(485	)		-
Non-cash unrealized gains on derivatives		(68,845	)		(4,064	)		(33,212	)		(34,566	)
Non-cash equity compensation expense		2,736			1,311			6,613			3,414
Impairment of oil and natural gas properties		(48	)		-			6,618			-
Gain on sale of oil and natural gas properties		-			(36,793	)		-			(40,617	)
Non-cash inventory write down expense		-			-			-			2,542
Dry hole and exploration costs		768			235			1,612			235
Adjusted EBITDAX		52,190			37,195			157,896			106,484

Less:
Income taxes		51			111			164			242
Cash interest expense, net		7,640			2,174			20,176			7,238
Realized losses on interest rate swaps		1,108			2,162			5,075			6,463
Estimated maintenance capital expenditures (1)		12,614			8,716			37,060			25,130
Distributable Cash Flow	$	30,777		$	24,032		$	95,421		$	67,411

(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.

Hedge Summary Table (as of 11/8/2011)

		Swap	Swap	Collar	Collar	Collar
Period	Index	Volume	Price	Volume	Floor	Ceiling
		(MmmBtu /MBbls)		(MmmBtu /MBbls)
Natural Gas
4Q 2011	NYMEX	3,725.3	$6.35	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	7,389.2	$6.53	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	6,918.4	$6.66	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	17,264.5	$5.62
	El Paso Permian	1,095.0	$6.77
	El Paso San Juan	1,095.0	$6.66

2014	NYMEX	15,184.0	$5.73

2015	NYMEX	15,147.5	$5.97

Crude Oil
4Q 2011	WTI	120.2	$93.19	118.3	$105.66	$156.16

1Q 2012	WTI	198.8	$94.51	113.6	$104.54	$156.77
2Q 2012	WTI	189.7	$94.43	113.6	$104.54	$156.77
3Q 2012	WTI	187.2	$94.28	114.8	$104.54	$156.77
4Q 2012	WTI	178.0	$94.21	114.8	$104.54	$156.77

Hedge Summary Table (as of 11/8/2011) cont.

		Swap	Swap
Period	Index	Volume	Price
		(MmmBtu /MBbls)
Crude Oil
1Q 2013	WTI	281.3	$86.65
2Q 2013	WTI	279.8	$86.47
3Q 2013	WTI	278.3	$86.32
4Q 2013	WTI	273.7	$86.14

1Q 2014	WTI	252.0	$89.26
2Q 2014	WTI	254.8	$89.26
3Q 2014	WTI	251.5	$91.84
4Q 2014	WTI	248.4	$95.23

Ethane
4Q 2011	Mt. Belvieu(Non-TET)-OPIS	92.0	$19.79

Propane
4Q 2011	Mt. Belvieu(Non-TET)-OPIS	55.2	$50.20

Basis Swaps
Premium to NYMEX
4Q 2011	Dominion Appalachia	87.2	$0.1975
4Q 2011	Columbia Appalachia	23.8	$0.1500

		Notional	Fixed
		Amount	Rate
Interest Rate Swap Agreements		(in $ mill)
October 2011 - July 2012		90.0	4.157%
October 2011 - September 2012		40.0	2.145%
July 2012 - July 2015		110.0	3.315%

EV Energy Partners, L.P., Houston

Michael E. Mercer, 713-651-1144

http://www.evenergypartners.com

Attached files

Stock widget

Investing forum

Harvest Oil & Gas Corp. Reports