SOURCE: EV Energy Partners, L.P.

EV Energy Partners, L.P.

February 29, 2012 16:14 ET

EV Energy Partners Announces Full Year and Fourth Quarter 2011 Results, 2012 Guidance and Updated Hedge Positions

HOUSTON, TX--(Marketwire - Feb 29, 2012) - EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the full year and fourth quarter 2011 and the filing of its Form 10-K with the Securities and Exchange Commission. In addition, EVEP announced 2012 guidance and an update of its commodity hedge positions presented in the Hedge Summary Table at the end of this release.

Full Year 2011 Results

Adjusted EBITDAX and distributable cash flow for 2011 were $212.4 million and $126.2 million, increases of 43 percent and 34 percent, respectively, over 2010. The increase in Adjusted EBITDAX and Distributable Cash Flow are primarily due to acquisitions made in 2010 and 2011 and higher realized oil and NGL prices partially offset by lower realized gas prices. Adjusted EBITDAX and distributable cash flow are described in the attached table under "Non-GAAP Measures".

Production for 2011 was 29.2 Bcf of natural gas, 891 MBbls of oil and 1,096 MBbls of natural gas liquids, or 41.2 billion cubic feet equivalents (Bcfe). This represents a 47 percent increase over 2010 production of 27.9 Bcfe, primarily due to acquisitions in 2010 and 2011.

For 2011, EVEP reported net income of $102.6 million, or $2.71 and $2.68 per basic and diluted weighted average limited partner unit outstanding, respectively. Included in net income were $35.5 million of unrealized gains on commodity and interest rate derivatives, which includes a $5.3 million unrealized gain on derivatives acquired in conjunction with a 2010 acquisition and $9.8 million of non-cash costs contained in general and administrative expenses. Also contained in general and administrative expenses were approximately $2.9 million of due diligence and other transaction costs for acquisitions. Other expenses incurred include $12.1 million of dry hole and exploration costs and $11.0 million of impairment costs related to divestitures of non-core oil and natural gas properties and assets held for sale. Also recognized, during the fourth quarter, was a $4.0 million gain on sale of assets related to Utica Shale acreage in an agreement with Total and Chesapeake. For 2010, EVEP reported net income of $106.1 million, or $3.35 and $3.34 per basic and diluted weighted average limited partner unit outstanding, respectively. Included in net income were $3.0 million of 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 for acquisitions. Also recognized was 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.

Fourth Quarter 2011 Results

Adjusted EBITDAX for the fourth quarter of 2011 was $54.5 million, a 31 percent increase over the fourth quarter of 2010 and a 4 percent increase over the third quarter of 2011. Distributable cash flow for the fourth quarter of 2011 was $30.8 million, a 15 percent increase over the fourth quarter of 2010 and flat to the third quarter of 2011.

Production for the fourth quarter of 2011 was 8.1 Bcf of natural gas, 235 MBbls of oil and 269 MBbls of natural gas liquids, or 11.1 Bcfe. This represents a 34 percent increase over fourth quarter 2010 production of 8.3 Bcfe and a 10 percent increase over third quarter 2011 production of 10.1. The increases in production are, primarily due to acquisitions completed during the fourth quarters of 2011 and 2010.

EVEP reported net income of $9.7 million, or $0.27 per basic and diluted weighted average limited partner unit outstanding, for the fourth quarter of 2011. Included in net income were $2.3 million of unrealized gains on commodity and interest rate derivatives, which includes a $1.1 million dollar unrealized gain on derivatives acquired in conjunction with a 2010 acquisition, $10.5 million of dry hole and exploration costs, $4.4 million of impairment costs primarily related to assets held for sale, a $4.0 million gain on the sale of assets related to Utica Shale acreage in an agreement with Total and Chesapeake and $3.2 million of non-cash costs contained in general and administrative expenses. Also contained in general and administrative expenses were approximately $2.3 million of due diligence and other transaction costs for acquisitions completed during the quarter. 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 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 for acquisitions completed during the quarter. For the third quarter of 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. Included in net income were $68.8 million of 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.

The $2.3 million unrealized gain on commodity and interest rate derivatives for the fourth quarter of 2011 was due to the decrease in future natural gas prices, significantly offset by the increase in future crude oil prices that occurred from September 30, 2011 to December 31, 2011 and the effect of such price changes on the mark-to-market valuation of EVEP's outstanding derivatives.

John Walker, Executive Chairman said, "We are pleased with our results for 2011, including the almost $500 million of accretive acquisitions in core areas of operations. We look forward to 2012 as we integrate these acquisitions into our asset base and begin the process of pursuing alternatives for the sale or monetization of all or a portion of our working interest position in the Utica Shale."

2012 Guidance

1st Qtr 2012 2nd Qtr 2012 3rd Qtr 2012
Net Production:
Natural Gas (MMcf) 9,600 - 10,600 9,900 - 10,900 10,250 - 11,300
Crude Oil (MBbls) 255 - 275 255 - 275 275 - 295
Natural Gas Liquids (MBbls) 400 - 445 400 - 445 410 - 455
Total Mmcfe 13,530 - 14,920 13,830 - 15,220 14,360 - 15,800
Average Daily Production (Mmcfe/d) 148.7 - 164.0 152.0 - 167.3 156.1 - 171.7
Average Price Differential vs NYMEX
Natural Gas (% of NYMEX Natural Gas) 96 % - 102 % 96 % - 102 % 96 % - 103 %
Crude Oil (% of NYMEX Crude Oil) 92 % - 98 % 92 % - 98 % 91 % - 97 %
Transportation Margin ($ thous) (a) 300 - 350 300 - 350 300 - 350
Expenses:
Operating Expenses:
LOE and other ($ thous) 24,500 - 27,500 25,000 - 28,000 25,600 - 28,600
Production Taxes (as % of revenue) 4.1 % - 4.5 % 4.1 % - 4.5 % 4.0 % - 4.4 %
General and administrative expense ($ thous) (b) 6,950 - 7,800 5,550 - 6,200 5,550 - 6,200
Capital Expenditures ($ thous) (c) 31,000 - 40,000 41,000 - 51,000 43,000 - 55,000
4th Qtr 2012 Full Year 2012
Net Production:
Natural Gas (MMcf) 10,500 - 11,700 40,250 44,500
Crude Oil (MBbls) 280 - 310 1,065 1,155
Natural Gas Liquids (MBbls) 435 - 475 1,645 1,820
Total Mmcfe 14,790 - 16,410 56,510 62,350
Average Daily Production (Mmcfe/d) 160.8 - 178.4 154.4 170.4
Average Price Differential vs NYMEX
Natural Gas (% of NYMEX Natural Gas) 96 % - 103 % 96 % 103 %
Crude Oil (% of NYMEX Crude Oil) 91 % - 97 % 91 % 97 %
Transportation Margin ($ thous) (a) 300 - 350 1,200 1,400
Expenses:
Operating Expenses:
LOE and other ($ thous) 25,900 - 28,900 101,000 113,000
Production Taxes (as % of revenue) 3.8 % - 4.2 % 4.0 % 4.4 %
General and administrative expense ($ thous) (b) 5,550 - 6,200 23,600 26,400
Capital Expenditures ($ thous) (c) 25,000 - 34,000 140,000 180,000
(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, also excludes any amounts for future acquisition related due diligence and 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 2011 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 web site by March 5, 2012 will be unitholders' Schedule K-1's for the tax year 2011. 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 February 24, 2012, EV Energy Partners, L.P. will host an investor conference call on February 29, 2012, at 5:00 p.m. Eastern Time (4:00 p.m. Central). Investors interested in participating in the call may dial (480) 629-9722 (quote conference ID 4519964) 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. Financial results will also be posted in the investor relations section on the web site.

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,
2011 2010 2011 2010
Production data:
Oil (MBbls) 235 202 891 679
Natural gas liquids (MBbls) 269 187 1,096 728
Natural gas (MMcf) 8,103 5,958 29,247 19,486
Net production (MMcfe) 11,125 8,295 41,169 27,933
Average sales price per unit:
Oil (Bbl) $ 92.39 $ 79.57 $ 91.72 $ 74.78
Natural gas liquids (Bbl) 53.82 46.54 52.99 42.64
Natural gas (Mcf) 3.64 3.75 3.99 4.30
Mcfe 5.90 5.69 6.23 5.93
Average unit cost per Mcfe:
Production costs:
Lease operating expenses $ 1.78 $ 1.78 $ 1.81 $ 1.92
Production taxes 0.25 0.26 0.27 0.28
Total 2.03 2.04 2.08 2.20
Asset retirement obligations accretion expense 0.10 0.13 0.10 0.11
Depreciation, depletion and amortization 1.84 2.01 1.82 1.98
General and administrative expenses 1.00 0.81 0.85 0.83
Consolidated Balance Sheets
(in $ thousands)
December 31, 2011 December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents $ 30,312 $ 23,127
Accounts receivable:
Oil, natural gas and natural gas liquids revenues 36,926 27,742
Other 459 441
Derivative asset 81,772 55,100
Other current assets 3,084 1,158
Assets held for sale 6,597 -
Total current assets 159,150 107,568
Oil and natural gas properties, net of accumulated depreciation, depletion, and amortization; December 31, 2011, $244,092; December 31, 2010, $176,897 1,768,529 1,324,240
Other property, net of accumulated depreciation and amortization; December 31, 2011, $447; December 31, 2010, $465 1,345 1,567
Long-term derivative asset 57,643 51,497
Other assets 16,557 1,885
Total assets $ 2,003,224 $ 1,486,757
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Third party $ 34,705 $ 20,678
Related party 870 182
Derivative liability 618 1,943
Liabilities held for sale 602 -
Total current liabilities 36,795 22,803
Asset retirement obligations 90,803 67,175
Long-term debt 953,023 619,000
Other long-term liabilities 2,564 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 December 31, 2011 and 2010, respectively 935,425 779,327
Class B unitholders - 3,873,357 units issued and outstanding as of December 31, 2011 232 -
General partner interest (15,618 ) (5,380 )
Total owners' equity 920,039 773,947
Total liabilities and owners' equity $ 2,003,224 $ 1,486,757
Consolidated Statements of Operations
(in $ thousands, except per unit data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2011 2010 2011 2010
Revenues:
Oil, natural gas and natural gas liquids revenues $ 65,679 $ 47,184 $ 256,370 $ 165,738
Transportation and marketing-related revenues 1,157 1,228 5,470 5,780
Total revenues 66,836 48,412 261,840 171,518
Operating costs and expenses:
Lease operating expenses 19,824 14,795 74,419 53,736
Cost of purchased natural gas 836 906 4,078 4,353
Dry hole and exploration costs 10,528 182 12,140 417
Production taxes 2,832 2,191 11,247 7,867
Asset retirement obligations accretion expense 1,058 1,109 3,914 3,153
Depreciation, depletion and amortization 20,491 16,685 74,723 55,221
General and administrative expenses 11,117 6,750 34,968 23,313
Impairment of oil and natural gas properties 4,419 - 11,037 -
Gain on sales of oil and natural gas properties (4,017 ) (39 ) (4,017 ) (40,656 )
Total operating costs and expenses 67,088 42,579 222,509 107,404
Operating (loss) income (252 ) 5,833 39,331 64,114
Other income (expense), net:
Realized gains on derivatives, net 16,704 13,871 58,402 49,042
Unrealized gains (losses) on derivatives, net 2,293 (31,572 ) 35,505 2,994
Interest expense (9,113 ) (2,751 ) (30,568 ) (10,442 )
Other income, net 217 174 325 628
Total other income (expense), net 10,101 (20,278 ) 63,664 42,222
Income (loss) before income taxes 9,849 (14,445 ) 102,995 106,336
Income taxes (190 ) (43 ) (354 ) (285 )
Net income (loss) $ 9,659 $ ( 14,488 ) $ 102,641 $ 106,051
General partner's interest in net income, including incentive distribution rights $ 193 $ 2,338 $ 10,886 $ 11,938
Limited partners' interest net income (loss) $ 9,466 $ ( 16,826 ) $ 91,755 $ 94,113
Net income (loss) per limited partner unit:
Basic $ 0.27 $ (0.55 ) $ 2.71 $ 3.35
Diluted $ 0.27 $ (0.55 ) $ 2.68 $ 3.34
Weighted average limited partner units outstanding:
Basic 35,231 30,630 33,895 28,095
Diluted 35,571 30,630 34,183 28,162
Distributions declared per unit $ 0.763 $ 0.759 $ 3.046 $ 3.030
Consolidated Statements of Cash Flows
(in $ thousands)
Twelve Months Ended Twelve Months Ended
December 31, 2011 December 31, 2010
Cash flows from operating activities:
Net income $ 102,641 $ 106,051
Adjustments to reconcile net income to net cash flows provided by operating activities:
Dry hole costs 9,220 170
Asset retirement obligations accretion expense 3,914 3,153
Depreciation, depletion and amortization 74,723 55,221
Equity-based compensation 9,834 5,043
Impairment of oil and natural gas properties 11,037 -
Gain on sales of oil and natural gas properties (4,017 ) (40,656 )
Noncash derivative activity (40,187 ) (2,994 )
Amoritization of discount on long-term debt 523 -
Amoritization of deferred loan costs 1,348 564
Other 40 (169 )
Changes in operating assets and liabilities:
Accounts receivable (6,505 ) (9,320 )
Other current assets (342 ) 2,215
Accounts payable and accrued liabilities 7,362 4,514
Deferred revenues - -
Long-term liabilities - (734 )
Other, net (2,379 ) (705 )
Net cash flows provided by operating activities 167,212 122,353
Cash flows from investing activities:
Acquisitions of oil and natural gas properties (463,624 ) (568,433 )
Additions to oil and natural gas properties (75,913 ) (26,525 )
Proceeds from sales of oil and natural gas properties 14,012 44,399
Settlements from acquired derivatives 6,563 -
Net cash flows used in investing activities (518,962 ) (550,559 )
Cash flows from financing activities:
Long-term debt borrowings 477,500 543,000
Repayment of long-term debt borrowings (436,500 ) (226,000 )
Proceeds from debt offering 292,500 -
Loan costs paid (7,698 ) (465 )
Proceeds from public offering 147,108 204,965
Offering costs (347 ) (306 )
Contributions from general partner 3,191 4,267
Distributions paid (115,101 ) (92,934 )
Distributions related to acquisition (1,718 ) -
Net cash flows provided by financing activities 358,935 432,527
Increase in cash and cash equivalents 7,185 4,321
Cash and cash equivalents - beginning of period 23,127 18,806
Cash and cash equivalents - end of period $ 30,312 $ 23,127

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 and unrealized (gains) losses on derivatives, non-cash equity compensation, impairments of oil and natural gas properties, (gain) on sales of oil and natural gas properties, inventory write down, 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
December 31,
Twelve Months Ended
December 31,
2011 2010 2011 2010
Net income (loss) $ 9,659 $ ( 14,488 ) $ 102,641 $ 106,051
Add:
Income taxes 190 43 354 285
Interest expense, net 9,110 2,746 30,551 10,398
Realized losses on interest rate swaps 1,095 2,189 6,171 8,652
Depreciation, depletion and amortization 20,491 16,686 74,723 55,221
Asset retirement obligation accretion expense 1,058 1,109 3,914 3,153
Non-cash realized losses on commodity derivatives 1,061 - 577 -
Unrealized (gains) losses on derivatives (2,293 ) 31,571 (35,505 ) (2,994 )
Non-cash equity compensation expense 3,221 1,629 9,834 5,043
Impairment of oil and natural gas properties 4,419 - 11,037 -
Gain on sales of oil and natural gas properties (4,017 ) (39 ) (4,017 ) (40,656 )
Non-cash inventory write down expense - - - 2,542
Dry hole and exploration costs 10,528 182 12,140 417
Adjusted EBITDAX $ 54,522 $ 41,628 $ 212,418 $ 148,112
Less:
Income taxes 190 43 354 285
Cash interest expense, net 8,504 2,595 28,680 9,834
Realized losses on interest rate swaps 1,095 2,189 6,171 8,652
Estimated maintenance capital expenditures (1) 13,908 10,037 50,968 35,167
Distributable Cash Flow $ 30,825 $ 26,764 $ 126,246 $ 94,174
(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 (subsequent to 12/31/2011)
Swap Swap
Period Index Volume Price
Natural Gas (Mmmbtu/
Mbbls)
1Q 2012 NYMEX 840.0 $3.22
2Q 2012 NYMEX 1,274.0 $3.22
3Q 2012 NYMEX 1,840.0 $3.23
4Q 2012 NYMEX 2,116.0 $3.32
2013 NYMEX 3,650.0 $3.90
Crude Oil
1Q 2012 WTI 6.0 $101.85
2Q 2012 WTI 9.1 $101.85
3Q 2012 WTI 36.8 $101.60
4Q 2012 WTI 46.0 $100.55
2013 WTI 182.5 $98.40
Hedge Summary Table (as of 02/29/2012)
Swap Swap Collar Collar Collar
Period Index Volume Price Volume Floor Ceiling
Natural Gas (Mmmbtu/
Mbbls)
(Mmmbtu/
Mbbls)
1Q 2012 NYMEX 7,264.6 $4.97 508.1 $6.22 $6.94
El Paso Permian 182.0 $9.21
Dominion Appalachia 455.0 $8.95 $11.45
Houston Ship Channel 273.0 $8.25 $11.10
MichCon Citygate 409.5 $8.75 $11.05
2Q 2012 NYMEX 7,698.6 $4.87 508.1 $6.22 $6.94
El Paso Permian 182.0 $9.21
Dominion Appalachia 455.0 $8.95 $11.45
Houston Ship Channel 273.0 $8.25 $11.10
MichCon Citygate 409.5 $8.75 $11.05
3Q 2012 NYMEX 8,059.2 $4.76 513.7 $6.22 $6.94
El Paso Permian 184.0 $9.21
Dominion Appalachia 460.0 $8.95 $11.45
Houston Ship Channel 276.0 $8.25 $11.10
MichCon Citygate 414.0 $8.75 $11.05
4Q 2012 NYMEX 8,335.2 $4.73 513.7 $6.22 $6.94
El Paso Permian 184.0 $9.21
Dominion Appalachia 460.0 $8.95 $11.45
Houston Ship Channel 276.0 $8.25 $11.10
MichCon Citygate 414.0 $8.75 $11.05
2013 NYMEX 33,689.5 $4.83
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
1Q 2012 WTI 235.3 $95.16 113.6 $104.54 $156.77
2Q 2012 WTI 229.3 $95.20 113.6 $104.54 $156.77
3Q 2012 WTI 254.8 $95.79 114.8 $104.54 $156.77
4Q 2012 WTI 254.8 $95.82 114.8 $104.54 $156.77
1Q 2013 WTI 384.8 $89.22
2Q 2013 WTI 384.5 $89.11
3Q 2013 WTI 384.1 $89.04
4Q 2013 WTI 379.5 $88.94
1Q 2014 WTI 288.0 $89.50
2Q 2014 WTI 291.2 $89.50
3Q 2014 WTI 288.3 $91.76
4Q 2014 WTI 285.2 $94.71
Ethane
2012 OPIS - Mt Belvieu 732.0 $29.18
Propane
2012 OPIS - Mt Belvieu 366.0 $53.97
Interest Rate Swap Agreements Notional
Amount
Fixed
Rate
(in $ mill)
January 2012 - July 2012 90 4.157%
January 2012 - September 2012 40 2.145%
January 2012 - July 2015 110 3.315%

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