SOURCE: EV Energy Partners, L.P.

EV Energy Partners, L.P.

November 08, 2011 18:23 ET

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

HOUSTON, TX--(Marketwire - Nov 8, 2011) - 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)

Period

Index
Swap
Volume
Swap
Price
Collar
Volume
Collar
Floor
Collar
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
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 Amount Fixed
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 %

Contact Information