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HOUSTON, TX, Mar 16, 2010 (MARKETWIRE via COMTEX News Network) -- EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the full year and fourth quarter 2009, its year-end 2009 proved reserves and the filing of its Form 10-K with the Securities and Exchange Commission. In addition, EVEP provided 2010 guidance and its commodity hedge positions presented in the Hedge Summary Table at the end of this release.
Full Year 2009 Results
Adjusted EBITDA and distributable cash flow for 2009 were $132.2 million and $75.5 million, increases of 11% and 20%, respectively, over 2008 primarily due to acquisitions made during the second half of 2008 and in 2009, partially offset by lower realized natural gas prices. Adjusted EBITDA and distributable cash flow are described in the attached table under "Non-GAAP Measures."
Production for 2009 was 16.5 Bcf of natural gas, 514 MBbls of crude oil and 768 MBbls of natural gas liquids, or 24.2 Bcfe. This was an 18% increase over 2008 production of 20.5 Bcfe, primarily due to acquisitions made during the second half of 2008 and in 2009.
For 2009, EVEP reported net income of $1.4 million. Included in 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. For 2008, EVEP reported net income of $225.5 million. Included in 2008 net income was $164.9 million of non-cash net unrealized gains on commodity and interest rate derivatives and $1.2 million of non-cash costs contained in general and administrative expenses.
The $164.9 million non-cash net unrealized gains on commodity and interest rate derivatives for 2008 was primarily due to the significant decrease in future oil and natural gas prices that occurred from December 31, 2007 to December 31, 2008 and the effect of such decreased prices on the mark-to-market valuation of EVEP's outstanding derivatives.
Fourth Quarter 2009 Results
Adjusted EBITDA for the fourth quarter of 2009 was $34.5 million, an 8% increase over the fourth quarter of 2008 and a 3% increase over the third quarter of 2009. Distributable cash flow for the fourth quarter of 2009 was $21.2 million, a 42% increase over the fourth quarter of 2008 and a 9% increase over the third quarter of 2009.
For the fourth quarter of 2009, EVEP produced 4.29 Bcf of natural gas, 128 MBbls of crude oil and 188 MBbls of natural gas liquids, or 6.2 Bcfe. This is a 2% increase over fourth quarter 2008 production of 6.0 Bcfe, primarily from acquisitions made during the second half of 2008 and in 2009. Production increased by 1% from third quarter 2009 production of 6.1 Bcfe, primarily due to the acquisition made during the fourth quarter of 2009.
EVEP reported a net loss of $2.5 million for the fourth quarter of 2009. Included in net loss was $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. For the fourth quarter of 2008, EVEP reported a net income of $145.5 million which included $134.0 million of non-cash net unrealized gains on commodity and interest rate derivatives.
The $134.0 million non-cash net unrealized gains on commodity and interest rate derivatives for the fourth quarter of 2008 was primarily due to the significant decrease in future oil and natural gas prices that occurred from September 30, 2008 to December 31, 2008 and the effect of such decreased prices on the mark-to-market valuation of EVEP's outstanding derivatives.
John Walker, Chairman and CEO said, "We are very pleased with our results for 2009. We completed one Appalachian Basin and two Austin Chalk add-on acquisitions, as well as two successful equity offerings to finance the acquisitions and increase liquidity. During the year, we reduced our debt by $165 million. To date in 2010 we have announced a sizeable Appalachian Basin acquisition, which we expect to close by the end of March, and completed a 3.45 million common unit offering to finance the acquisition and provide capacity for additional acquisitions."
Year-End 2009 Estimated Net Proved Reserves
EVEP's year-end 2009 estimated net proved reserves were 365.6 billion cubic feet equivalents (Bcfe), a 2% increase over year-end 2008 estimated net proved reserves. Approximately 70% were natural gas, 18% were natural gas liquids and 12% were crude oil. In addition, 93% were categorized as proved developed. At December 31, 2009 the present value of future net pre-tax cash flows discounted at 10% was $352.8 million and the standardized measure of our estimated net proved reserves was $351.5 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%. 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.
Natural Crude Natural Gas
Gas Oil NGL's Equivalents
-------- -------- -------- ------------
(Bcf) (MMBbls) (MMBbls) (Bcfe)
Appalachian Basin 50.4 1.1 - 57.0
Michigan 42.3 - - 42.3
Monroe Field 67.2 - - 67.2
Central and East Texas 23.6 3.0 1.9 52.8
Permian Basin 25.9 0.7 4.7 58.6
San Juan Basin 34.3 1.2 3.7 63.3
Mid-Continent area 13.6 1.4 0.4 24.4
-------- -------- -------- ------------
Total Proved Reserves 257.3 7.4 10.7 365.6
Proved Developed Reserves 245.0 6.8 9.1 340.4
The decrease in the natural gas price utilized in calculating our year-end 2009 proved reserves compared with prices used in calculating our year-end 2008 proved reserves had a significant negative impact on EVEP's estimated net proved reserves at December 31, 2009, partially offset by an increase in the calculated crude oil and natural gas liquids price. The prices used in determining our estimated net proved reserves at December 31, 2009 were $61.18 per Bbl of oil and $3.866 per MMBtu of natural gas as compared to $44.60 per Bbl of oil and $5.71 per MMBtu of natural gas at December 31, 2008. Had the commodity prices used in calculating year-end 2009 proved reserves been the same as those in effect at December 31, 2008, EVEP's estimated net proved reserves at December 31, 2009 would have been approximately 384.2 Bcfe (a 7% increase over year-end 2008 estimated net proved reserves), and the present value of future net pre-tax cash flows discounted at 10% at December 31, 2009 would have been approximately $442.4 million. In addition, if NYMEX strip prices in effect at December 31, 2009 had been used, year-end 2009 estimated proved reserves would have been approximately 440.5 Bcfe and the present value of future net pre-tax cash flows discounted at 10% at December 31, 2009 would have been approximately $756.7 million.
2010 Guidance
Guidance estimates for 2010 are presented in the table below.
1st Qtr 2010 2nd-4th Qtrs 2010
------------------ -------------------
Net Production:
Natural Gas (MMcf) 4,000 - 4,300 14,250 - 15,750
Crude Oil (MBbls) 120 - 140 520 - 580
Natural Gas Liquids
(MBbls) 170 - 190 520 - 580
Total Mmcfe 5,740 - 6,280 20,490 - 22,710
Average Daily Production
(Mmcfe/d) 63.8 - 69.8 74.5 - 82.6
Average Price Differential
vs NYMEX
Natural Gas (% of NYMEX
Natural Gas) 97% - 103% 96% - 103%
Crude Oil (% of NYMEX
Crude Oil) 91% - 97% 90% - 96%
Natural Gas Liquids (% of
NYMEX Crude Oil) 56% - 62% 54% - 60%
Transportation Margin ($
thous) (a) 325 - 375 975 - 1,125
Expenses:
Operating Expenses:
LOE and other ($ thous) 10,000 - 11,000 34,000 - 37,000
Production Taxes (as % of
revenue) 5.3% - 5.7% 4.6% - 5.0%
General and administrative
expense ($ thous) (b) 3,500 - 3,900 11,000 - 13,000
Capital Expenditure ($
thous) (c) 2,000 - 5,000 18,000 - 25,000
(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.
Annual Report on Form 10-K and Unitholders' Schedule K-1
EVEP's financial statements and related footnotes are available on our 2009 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 are unitholders' Schedule K-1 for the tax year 2009. For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1 (800) 973-7551.
Conference Call
As announced on March 12, 2010, EV Energy Partners, L.P. will host an investor conference call Wednesday, March 17, 2010, at 10:00am (Eastern Daylight Time). Investors interested in participating in the call may dial (480)-629-9819 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. 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 Twelve Months
Ended Ended
December 31, December 31,
--------------- ---------------
2009 2008 2009 2008
------- ------- ------- -------
Production data:
Oil (MBbls) 128 136 514 437
Natural gas liquids (MBbls) 188 157 768 543
Natural gas (MMcf) 4,288 4,274 16,519 14,578
------- ------- ------- -------
Net production (MMcfe) 6,184 6,034 24,210 20,457
Average sales price per unit (1):
Oil (Bbl) $ 71.92 $ 58.01 $ 56.17 $ 94.76
Natural gas liquids (Bbl) 41.09 28.07 31.08 54.75
Natural gas (Mcf) 4.15 5.88 3.71 8.34
Mcfe 5.61 6.20 4.71 9.42
Average unit cost per Mcfe:
Production costs:
Lease operating expenses $ 1.69 $ 2.01 $ 1.71 $ 2.09
Production taxes 0.30 0.31 0.25 0.44
------- ------- ------- -------
Total 1.99 2.32 1.96 2.53
Asset retirement obligations accretion
expense 0.09 0.07 0.08 0.07
Depreciation, depletion and amortization 2.06 2.29 2.15 1.86
General and administrative expenses 0.92 0.63 0.77 0.67
(1) Prior to $16.0 and $10.9 million of net hedge gains for the three
months ended December 31, 2009 and December 31, 2008, respectively, and
prior to $77.3 and ($13.0) million of net realized hedge gains (losses) for
the twelve months ended December 31, 2009 and December 31, 2008,
respectively.
Consolidated Balance Sheets
(in $ thousands)
December 31, December 31,
2009 2008
----------- ------------
ASSETS
Current assets:
Cash and cash equivalents $ 18,806 $ 41,628
Accounts receivable:
Oil, natural gas and natural gas liquids
revenues 14,599 17,588
Related party 2,881 1,463
Other 1,034 3,278
Derivative asset 26,733 50,121
Prepaid expenses and other current assets 625 1,037
----------- ------------
Total current assets 64,678 115,115
Oil and natural gas properties, net of
accumulated depreciation, depletion and
amortization; December 31, 2009, $121,970;
December 31, 2008, $69,958 771,752 765,243
Other property, net of accumulated depreciation
and amortization; December 31, 2009, $319;
December 31, 2008, $284 742 180
Long-term derivative asset 68,549 96,720
Other assets 1,984 2,737
----------- ------------
Total assets $ 907,705 $ 979,995
=========== ============
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 10,310 $ 14,063
Deferred revenues 4,120
Derivative liability 1,543 2,115
----------- ------------
Total current liabilities 11,853 20,298
Asset retirement obligations 42,533 33,787
Long-term debt 302,000 467,000
Other long-term liabilities 3,212 1,426
Long-term derivative liability 676
Commitments and contingencies
Owners' equity
Common unitholders 548,160 432,031
Subordinated unitholders 21,618
General partner interest (729) 3,835
Total owners' equity 547,431 457,484
----------- ------------
Total liabilities and owners' equity $ 907,705 $ 979,995
=========== ============
Consolidated Statements of Operations
(in $ thousands, except per unit data)
Three Months Ended Twelve Months Ended
December 31, December 31,
2009 2008 2009 2008
--------- --------- --------- ---------
Revenues:
Oil, natural gas and natural
gas liquids revenues $ 34,705 $ 37,421 $ 114,066 $ 192,757
Gain on derivatives, net - 372 - 1,597
Transportation and
marketing-related revenues 1,445 3,310 7,846 12,959
--------- --------- --------- ---------
Total revenues 36,150 41,103 121,912 207,313
--------- --------- --------- ---------
Operating costs and expenses:
Lease operating expenses 10,420 12,139 41,495 42,681
Cost of purchased natural gas 1,078 1,983 4,509 9,849
Production taxes 1,840 1,867 5,983 9,088
Asset retirement obligations
accretion expense 527 447 2,035 1,434
Depreciation, depletion and
amortization 12,744 13,845 52,048 38,032
General and administrative
expenses 5,686 3,786 18,556 13,653
--------- --------- --------- ---------
Total operating costs and
expenses 32,295 34,067 124,626 114,737
--------- --------- --------- ---------
Operating income (loss) 3,855 7,036 (2,714) 92,576
Other (expense) income, net:
Realized gains (losses) on
mark-to-market derivatives,
net 13,783 10,210 68,984 (14,557)
Unrealized (losses) gains on
mark-to-market derivatives,
net (17,261) 133,584 (51,665) 163,270
Interest expense (2,412) (5,565) (12,321) (16,128)
Other (expense) income, net (309) 307 (626) 559
--------- --------- --------- ---------
Total other (expense) income,
net (6,199) 138,536 4,372 133,144
--------- --------- --------- ---------
(Loss) income before income
taxes (2,344) 145,572 1,658 225,720
Income taxes (127) (30) (248) (235)
--------- --------- --------- ---------
Net (loss) income ($ 2,471) $ 145,542 $ 1,410 $ 225,485
========= ========= ========= =========
General partner's interest in
net income, including
incentive distribution rights $ 1,941 $ 4,259 $ 7,040 $ 8,847
========= ========= ========= =========
Limited partners' interest in
net (loss) income ($ 4,412) $ 141,283 ($ 5,630) $ 216,638
========= ========= ========= =========
Net (loss) income per limited
partner unit (basic and
diluted): ($ 0.19) $ 8.76 ($ 0.29) $ 14.12
Weighted average limited
partner units outstanding
(basic and diluted):
Common units 21,892 13,027 16,524 12,240
Subordinated units 1,584 3,100 2,718 3,100
Performance units 107 60
Consolidated Statements of Cash Flows
(in $ thousands)
Twelve Twelve
Months Ended Months Ended
December 31, December 31,
2009 2008
------------ ------------
Cash flows from operating activities:
Net income $ 1,410 $ 225,485
Adjustments to reconcile net income to net
cash flows provided by operating activities:
Asset retirement obligations accretion
expense 2,035 1,434
Depreciation, depletion and amortization 52,048 38,032
Equity-based compensation 3,659 1,241
Amortization of deferred loan costs 799 370
Unrealized loss (gain) on mark-to-market
derivatives 51,665 (164,867)
Other 544 -
Changes in operating assets and liabilities:
Accounts receivable 3,955 327
Prepaid expenses and other current assets 214 (151)
Accounts payable and accrued liabilities (2,126) (233)
Deferred revenues (4,120) 2,998
Other, net (558) (265)
------------ ------------
Net cash flows provided by operating activities 109,525 104,371
------------ ------------
Cash flows from investing activities:
Acquisitions of oil and natural gas
properties, net of cash acquired (39,646) (176,992)
Development of oil and natural gas properties (14,271) (33,017)
------------ ------------
Net cash flows used in investing activities (53,917) (210,009)
------------ ------------
Cash flows from financing activities:
Long-term debt borrowings 20,000 197,000
Repayments of long-term debt borrowings (185,000) -
Proceeds from equity offerings 149,038 -
Offering costs (484) -
Distributions related to acquisitions - (13,918)
Loan costs incurred (44) (1,331)
Contributions by partners 3,077 601
Distributions to partners and dividends paid (65,017) (45,306)
------------ ------------
Net cash flows (used in) provided by financing
activities (78,430) 137,046
------------ ------------
(Decrease) increase in cash and cash
equivalents (22,822) 31,408
Cash and cash equivalents - beginning of period 41,628 10,220
------------ ------------
Cash and cash equivalents - end of period $ 18,806 $ 41,628
============ ============
Non GAAP Measures
We define Adjusted EBITDA as net income (loss) plus income tax provision, interest expense, net, realized (gains) losses on interest rate swaps, depreciation, depletion and amortization, asset retirement obligation accretion expense, non-cash (gains) losses on derivatives, amortization of upfront premiums paid to enter into commodity price hedge agreements and non-cash equity compensation. Distributable Cash Flow is defined as Adjusted EBITDA less income tax provision, 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 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 Income to Adjusted EBITDA and Distributable Cash Flow
(in $ thousands)
Three Months Ended Twelve Months Ended
December 31, December 31,
2009 2008 2009 2008
--------- --------- ---------- ---------
Net (loss) income ($ 2,471) $ 145,542 $ 1,410 $ 225,485
Add:
Income taxes 127 30 248 235
Interest expense, net 2,405 5,434 12,189 15,756
Realized (gains) losses on
interest rate swaps 2,200 742 8,351 1,598
Depreciation, depletion and
amortization 12,744 13,845 52,048 38,032
Asset retirement obligation
accretion expense 527 447 2,035 1,434
(Gains) on settlement of asset
retirement obligations (182) (182)
Non-cash losses (gains) on
derivatives 17,261 (133,956) 51,665 (164,867)
Amortization of premiums on
derivatives 209 - 608 -
Non-cash equity compensation
expense 1,462 33 3,659 1,241
--------- --------- ---------- ---------
Adjusted EBITDA 34,464 31,935 132,213 118,732
Less:
Income taxes 127 30 248 235
Interest expense, net 2,405 5,434 12,189 15,756
Realized losses on interest
rate swaps 2,200 742 8,351 1,598
Amortization of premiums on
derivatives 209 - 608 -
Estimated maintenance capital
expenditures (1) 8,348 10,800 35,360 38,205
--------- --------- ---------- ---------
Distributable Cash Flow 21,175 14,929 75,457 62,938
(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 12/31/2009)
Swap Swap Collar Collar Collar
Volume Price Volume Floor Ceiling
----------- --------- --------- -------- --------
(Mmmbtu/ (Mmmbtu/
Mbbls) Mbbls)
Natural Gas
1Q 2010
NYMEX 1,845 $ 7.53 135 $ 7.50 $ 10.00
Dominion Appalachia 601 $ 8.19
El Paso Permian 225 $ 7.68
Houston Ship Channel 136 $ 5.78 315 $ 7.25 $ 9.55
MichCon Citygate 450 $ 8.34
Appalachia Columbia 27 $ 5.75
2Q 2010
NYMEX 1,775 $ 7.62 137 $ 7.50 $ 10.00
Dominion Appalachia 608 $ 8.19
El Paso Permian 228 $ 7.68
Houston Ship Channel 138 $ 5.78 319 $ 7.25 $ 9.55
MichCon Citygate 455 $ 8.34
Appalachia Columbia 27 $ 5.75
3Q 2010
NYMEX 1,702 $ 7.74 138 $ 7.50 $ 10.00
Dominion Appalachia 614 $ 8.19
El Paso Permian 230 $ 7.68
Houston Ship Channel 139 $ 5.78 322 $ 7.25 $ 9.55
MichCon Citygate 460 $ 8.34
Appalachia Columbia 28 $ 5.75
4Q 2010
NYMEX 1,610 $ 7.88 138 $ 7.50 $ 10.00
Dominion Appalachia 614 $ 8.19
El Paso Permian 230 $ 7.68
Houston Ship Channel 139 $ 5.78 322 $ 7.25 $ 9.55
MichCon Citygate 460 $ 8.34
Appalachia Columbia 28 $ 5.75
2011
NYMEX 5,585 $ 8.18 441 $ 5.85 $ 7.55
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
2012
NYMEX 5,527 $ 8.63
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
2013
NYMEX 3,285 $ 7.23
El Paso Permian 1,095 $ 6.77
El Paso San Juan 1,095 $ 6.66
Through 8/31/2014
NYMEX 1,215 $ 7.06
Crude Oil
(NYMEX)
2010 688.0 $ 89.81
2011 219.0 $ 103.66 401.5 $ 110.00 $ 166.45
2012 205.0 $ 104.05 366.0 $ 110.00 $ 170.85
2013 511.0 $ 78.64
Through 07/31/2014 106.0 $ 84.60
Through 8/31/2014 194.4 $ 82.28
Basis Swaps to NYMEX:
2010
El Paso Permian 365 ($ 0.2750)
PEPL TX/OK 730 ($ 0.3000)
El Paso San Juan 1,643 ($ 0.3400)
2011
Dominion Appalachia 346 $ 0.1975
Appalachia Columbia 95 $ 0.1500
Interest Rate Swap
Agreements:
Notional Fixed Floating
Amount Rate Rate
(in $ mill)
Through July 2012 $ 200 4.163% 1mo LIBOR
Through Sept 2012 $ 40 2.145% 1mo LIBOR
EV Energy Partners, L.P., Houston Michael E. Mercer 713-651-1144 http://www.evenergypartners.com
SOURCE: EV Energy Partners, L.P.
http://www.evenergypartners.com
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