SOURCE: EV Energy Partners, L.P.

EV Energy Partners, L.P.

August 09, 2011 18:10 ET

EV Energy Partners Announces Second Quarter 2011 Results and Utica Shale Update

HOUSTON, TX--(Marketwire - Aug 9, 2011) - EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the second quarter 2011 and filed its Form 10-Q with the Securities and Exchange Commission.

Second Quarter 2011 Results

Adjusted EBITDAX for the quarter was $55.1 million, a 49 percent increase over the second quarter of 2010 and a 9 percent increase versus the first quarter of 2011. Distributable Cash Flow for the quarter was $33.1 million, a 43 percent increase over the second quarter of 2010 and a 5 percent increase versus the first quarter of 2011. The increases in Adjusted EBITDAX and Distributable Cash Flow, which are described in the attached table under "Non-GAAP Measures," are primarily related to acquisitions completed during the second half of 2010 as well as improved commodity pricing.

For the quarter ended June 30, 2011, EVEP produced 7.0 Bcf of natural gas, 241 MBbls of crude oil and 272 MBbls of natural gas liquids, or 10.1 Bcfe. This represents a 48 percent increase from the second quarter 2010 production of 6.8 Bcfe, primarily due to acquisitions completed during the second half of 2010, and a 2 percent increase over the first quarter 2011 production of 9.9 Bcfe.

EVEP reported net income of $39.2 million, or $1.03 per basic and diluted weighted average limited partner unit outstanding, for the second quarter of 2011. 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 recent 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. For the second quarter of 2010, net income was $16.3 million, or $0.50 per basic and diluted weighted average limited partner unit outstanding, which included $2.2 million of non-cash net unrealized losses on commodity and interest rate derivatives and $1.0 million of non-cash costs contained in general and administrative expenses. For the first quarter of 2011, net loss was $34.0 million, or ($1.14) per basic and diluted weighted average limited partner unit outstanding. Included in net loss were $54.6 million of non-cash net unrealized losses on commodity and interest rate derivatives and $2.1 million of non-cash costs contained in general and administrative expenses. General and administrative expenses also included $0.3 million of acquisition-related due diligence and other related transaction costs and $1.0 million of costs related to the annual vesting of phantom units during the first quarter of 2011. Also included in net loss was a $1.6 million impairment charge relating to a divestiture of non-core oil and natural gas properties.

The $17.4 million non-cash net unrealized gain on derivatives for the second quarter of 2011 was primarily due to the decrease in future commodity prices that occurred from March 31, 2011 to June 30, 2011 and the effect of such decreased prices on the mark-to-market valuation of EVEP's outstanding commodity derivatives.

Utica Shale Update

EnerVest partnerships, including EVEP, are uniquely positioned in Ohio with a combined 780,000 net acres of mostly held-by-production (HBP) acreage. Approximately 60% of this acreage is operated by EnerVest. EVEP has a total of approximately 159,000 net working interest acres in Ohio, along with the equivalent of a 7.5% overriding royalty interest on approximately 240,000 net acres.

John Walker, Chairman and CEO, said, "The EnerVest partnerships, including EVEP, recently finalized an agreement with Chesapeake (CHK) on a long-term joint venture to develop the emerging Utica shale of Eastern Ohio. We believe that CHK is a recognized worldwide leader in all the complex technical, regulatory, relational and logistical skills necessary to rapidly and efficiently develop a major liquids-rich shale play. CHK will operate about 40% of EnerVest's 780,000 net acres. EVEP retains the equivalent of a 7.5% override on 80,000 net acres and has approximately 22,000 net working interest acres in this joint venture. As announced by CHK in late July, they have five rigs drilling in the Utica, a few producing wells and several awaiting completion. The wells are testing all three legs of the play (oil, NGL and dry gas windows) as well as areas both within and outside the core of the play.

"EnerVest acts as the operator for EVEP and an EnerVest institutional partnership on over 400,000 net acres in Ohio separate from CHK, most of which are HBP. Within this acreage position EVEP has, on average, an approximate 33% interest (137,000 net working interest acres) and holds the equivalent of a 7.5% overriding royalty interest in approximately 160,000 net acres. Because of its proximity to the CHK joint venture, we believe that there will be meaningful cooperation with CHK's joint venture in forming drilling units and contracting for oilfield services and mid-stream operations, which involves maximizing value from ethane and other NGLs. EnerVest has permitted or is permitting ten wells and plans to drill two to three Utica laterals later this year and early next year.

"We are optimistic about the Utica shale, where Ohio records indicate 25 horizontal permits have been granted. We are awaiting more sustained test and production results from the spread of wells in various stages of drilling, completion, testing and production before we can assess the near-term value to EVEP. We expect these results to be released within 30 to 60 days.

"We are very fortunate that the EnerVest partnerships, including EVEP, are the largest conventional oil and gas producer in Ohio, a state recognized for its well-established and strictly-enforced regulations. The state's government leaders, led by Governor John Kasich, are very supportive of responsible development of the Utica shale and the thousands of jobs that we will directly and indirectly create there. Our long-established community, business and government relationships will play an important role as this massive project unfolds."

EVEP's financial statements and related footnotes are available on our second 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 July 28, 2011, EV Energy Partners, L.P. will host an investor conference call Wednesday, August 10, 2011 at 10 a.m. EDT. Investors interested in participating in the call may dial 1-480-629-9722 (quote conference ID 4462519) 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 June 30, Six Months Ended June 30,
2011 2010 2011 2010
Production data:
Oil (MBbls) 241 171 449 297
Natural gas liquids (MBbls) 272 178 542 360
Natural gas (MMcf) 6,999 4,734 14,003 8,719
Net production (MMcfe) 10,080 6,831 19,951 12,665
Average sales price per unit: (1)
Oil (Bbl) $ 98.63 $ 73.20 $ 94.58 $ 73.73
Natural gas liquids (Bbl) 54.80 40.23 51.45 42.91
Natural gas (Mcf) 4.20 4.16 4.10 4.66
Mcfe 6.76 5.77 6.40 6.16
Average unit cost per Mcfe:
Production costs:
Lease operating expenses (2) $ 1.78 $ 2.18 $ 1.77 $ 2.08
Production taxes 0.31 0.24 0.29 0.30
Total 2.09 2.42 2.06 2.38
Asset retirement obligations accretion expense 0.10 0.11 0.10 0.10
Depreciation, depletion and amortization 1.83 1.97 1.80 2.02
General and administrative expenses 0.71 0.85 0.79 0.83
(1) Prior to $12.8 and $16.0 million of net hedge gains and settlements on commodity derivatives for the three months ended June 30, 2011 and June 30, 2010, respectively and $30.0 and $26.2 million for the six months ended June 30, 2011 and June 30, 2010.
(2) Lease operating expenses for the three and six months ended June 30, 2010 include $2.3 million or $0.34 per mcfe and $2.5 million or $0.20 per mcfe, respectively of non-cash charges related to oil in tanks purchased in connection with the Appalachian Basin acquisitions closed during the fourth quarter of 2009 and the first quarter of 2010.
Condensed Consolidated Balance Sheets (Unaudited)
(In $ thousands, except number of units)
June 30, 2011 December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents $ 26,392 $ 23,127
Accounts receivable:
Oil, natural gas and natural gas liquids revenues 36,600 27,742
Related party 3,967 -
Other 300 441
Derivative asset 51,215 55,100
Assets held for sale 11,402 -
Other current assets 1,047 1,158
Total current assets 130,923 107,568
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; June 30, 2011, $210,073; December 31, 2010, $176,897 1,300,294 1,324,240
Other property, net of accumulated depreciation and amortization; June 30, 2011, $536; December 31, 2010, $465 1,495
1,567
Long-term derivative asset 26,576 51,497
Other assets 7,533 1,885
Total assets $ 1,466,821 $ 1,486,757
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Third party $ 27,642 $ 20,678
Related party - 182
Liabilities related to assets held for sale 2,895 -
Derivative liability 1,178 1,943
Total current liabilities 31,715 22,803
Asset retirement obligations 68,266 67,175
Long-term debt 480,183 619,000
Long-term liabilities 988 3,048
Long-term derivative liability 6,594 784
Commitments and contingencies
Owners' equity:
Common unitholders - 34,173,650 units and 30,510,313 units issued and outstanding as of June 30, 2011 and December 31, 2010, respectively 887,843 779,327
General partner interest (8,768 ) (5,380 )
Total owners' equity 879,075 773,947
Total liabilities and owners' equity $ 1,466,821 $ 1,486,757
Condensed Consolidated Statements of Operations (Unaudited)
(In $ thousands, except per unit data)
Three Months Ended June 30, Six Months Ended June 30,
2011 2010 2011 2010
Revenues:
Oil, natural gas and natural gas liquids revenues $ 68,109 $ 39,431 $ 127,730 $ 78,027
Transportation and marketing–related revenues 1,484 1,476 2,885 3,054
Total revenues 69,593 40,907 130,615 81,081
Operating costs and expenses:
Lease operating expenses 17,949 14,869 35,311 26,301
Cost of purchased natural gas 1,120 1,095 2,170 2,315
Dry hole and exploration costs 441 - 844 -
Production taxes 3,119 1,673 5,770 3,800
Asset retirement obligations accretion expense 970 764 1,936 1,274
Depreciation, depletion and amortization 18,443 13,436 36,007 25,520
General and administrative expenses 7,132 5,825 15,725 10,549
Impairment of oil and natural gas properties 5,078 - 6,666 -
Gain on sale of oil and natural gas properties - (4,388 ) - (3,824 )
Total operating costs and expenses 54,252 33,274 104,429 65,935
Operating income 15,341 7,633 26,186 15,146
Other income (expense), net:
Realized gains on derivatives, net 14,242 13,901 27,784 21,866
Unrealized gains (losses) on derivatives, net 17,422 (2,158 ) (35,633 ) 30,502
Interest expense (8,124 ) (3,269 ) (13,283 ) (5,372 )
Other income, net 313 252 233 393
Total other income (expense), net 23,853 8,726 (20,899 ) 47,389
Income before income taxes 39,194 16,359 5,287 62,535
Income taxes (31 ) (79 ) (113 ) (131 )
Net income $ 39,163 $ 16,280 $ 5,174 $ 62,404
General partner's interest in net income, including incentive distribution rights $ 3,728 $ 2,624 $ 5,982 $ 5,836
Limited partners' interest in net income (loss) $ 35,435 $ 13,656 $ (808 ) $ 56,568
Net income (loss) per limited partner unit:
Basic $ 1.03 $ 0.50 $ (0.02 ) $ 2.14
Diluted $ 1.03 $ 0.50 $ (0.02 ) $ 2.14
Weighted average limited partner units outstanding:
Basic 34,294 27,210 33,002 26,403
Diluted 34,534 27,264 33,002 26,438
Distributions declared per unit $ 0.761 $ 0.757 $ 1.521 $ 1.513
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In $ thousands)
Six Months Ended June 30,
2011 2010
Cash flows from operating activities:
Net Income $ 5,174 $ 62,404
Adjustments to reconcile net income to net cash flows provided by operating activities:
Asset retirement obligations accretion expense 1,936 1,274
Depreciation, depletion and amortization 36,007 25,520
Equity-based compensation cost 3,877 2,103
Impairment of oil and natural gas properties 6,666 -
Gain on sale of oil and natural gas properties - (3,824 )
Non-cash derivative activity 30,951 (30,502 )
Amortization of discount on long-term debt 183 -
Amortization of deferred loan costs 554 275
Other, net 56 (1 )
Changes in operating assets and liabilities:
Accounts receivable (12,866 ) (4,098 )
Other current assets 111 2,625
Accounts payable and accrued liabilities 7,630 879
Long-term liabilities - (734 )
Other, net (149 ) (119 )
Net cash flows provided by operating activities 80,130 55,802
Cash flows from investing activities:
Acquisition of oil and natural gas properties 3,101 (147,769 )
Development of oil and natural gas properties (33,686 ) (8,170 )
Proceeds from sale of oil and natural gas properties 1,170 4,471
Settlements from acquired derivatives 2,834 -
Earnest money received for sale of oil and natural gas properties 900 -
Net cash flows used in investing activities (25,681 ) (151,468 )
Cash flows from financing activities:
Long-term debt borrowings - 138,000
Repayment of long-term debt borrowings (431,500 ) (95,000 )
Proceeds from debt offering 292,500 -
Loan costs incurred (6,202 ) (8 )
Proceeds from public equity offering 147,108 92,770
Offering costs (308 ) (154 )
Contributions from general partner 3,191 1,977
Distributions paid (55,973 ) (43,433 )
Net cash flows (used in) provided by financing activities (51,184 ) 94,152
Increase (decrease) in cash and cash equivalents 3,265 (1,514 )
Cash and cash equivalents – beginning of period 23,127 18,806
Cash and cash equivalents – end of period $ 26,392 $ 17,292

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 (gains) on derivatives, non-cash unrealized (gains) losses 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 June 30, Six Months Ended June 30,
2011 2010 2011 2010
Net income $ 39,163 $ 16,280 $ 5,174 $ 62,404
Add:
Income taxes 31 79 113 131
Interest expense, net 8,118 3,264 13,272 5,340
Realized losses on interest rate swaps 1,828 2,143 3,967 4,301
Depreciation, depletion and amortization 18,443 13,436 36,007 25,520
Asset retirement obligation accretion expense 970 764 1,936 1,274
Non-cash realized (gains) on derivatives (3,279 ) - (1,784 ) -
Non-cash unrealized (gains) losses on derivatives (17,422 ) 2,158 35,633 (30,502 )
Non-cash equity compensation expense 1,739 1,037 3,877 2,103
Impairment of oil and natural gas properties 5,078 - 6,666 -
Gain on sale of oil and natural gas properties - (4,388 ) - (3,824 )
Non-cash inventory expense from 2009 Appalachian Basin acquisition included in lease operating expense - 2,302 - 2,542
Dry hole and exploration costs 441 - 844 -
Adjusted EBITDAX 55,110 37,075 105,705 69,289
Less:
Income taxes 31 79 113 131
Cash interest expense, net 7,600 3,126 12,535 5,065
Realized losses on interest rate swaps 1,828 2,143 3,967 4,301
Estimated maintenance capital expenditures (1) 12,600 8,539 24,446 16,414
Distributable Cash Flow $ 33,051 $ 23,188 $ 64,644 $ 43,378
(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 08/09/2011)
Swap Swap Collar Collar Collar
Period Index Volume Price Volume Floor Ceiling
(MmmBtu/
Mbbls)
(MmmBtu/
Mbbls)
Natural Gas
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
2014 NYMEX 14,600.0 $5.75
2015 NYMEX 14,600.0 $6.00
Crude Oil
3Q 2011 WTI 107.5 $94.91 118.3 $105.66 $156.16
4Q 2011 WTI 101.9 $95.12 118.3 $105.66 $156.16
1Q 2012 WTI 167.0 $96.49 113.6 $104.54 $156.77
2Q 2012 WTI 157.9 $96.50 113.6 $104.54 $156.77
3Q 2012 WTI 155.0 $96.38 114.8 $104.54 $156.77
4Q 2012 WTI 145.8 $96.43 114.8 $104.54 $156.77

Swap Swap Collar Collar Collar
Period Index Volume Price Volume Floor Ceiling
(Mmmbtu/
Mbbls)
(Mmmbtu/
Mbbls)
Crude Oil
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
3Q 2011 Mt. Belvieu(Non-TET)-OPIS 96.6 $20.32
4Q 2011 Mt. Belvieu(Non-TET)-OPIS 92.0 $19.79
Propane
3Q 2011 Mt. Belvieu(Non-TET)-OPIS 57.5 $49.36
4Q 2011 Mt. Belvieu(Non-TET)-OPIS 55.2 $50.20
Basis Swaps
Premium to NYMEX
2H 2011 Dominion Appalachia 174.4 $0.1975
2H 2011 Columbia Appalachia 47.7 $0.1500
Interest Rate Swap Notional Fixed
Agreements Amount Rate
(in $ mill)
July 2011 - July 2012 90.0 4.157%
July 2011 - Sept 2012 40.0 2.145%
July 2012 - July 2015 110.0 3.315%

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