Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Harvest Oil & Gas Corp. | v232019_8k.htm |
EV Energy Partners Announces Second Quarter 2011 Results and Utica Shale Update
HOUSTON, TX – August 9, 2011 -- (MARKETWIRE) -- 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
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Three Months Ended
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Six Months Ended
|
|||||||||||||||
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June 30,
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June 30,
|
|||||||||||||||
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2011
|
2010
|
2011
|
2010
|
|||||||||||||
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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 | ||||||||||||
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Net production (MMcfe)
|
10,080 | 6,831 | 19,951 | 12,665 | ||||||||||||
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Average sales price per unit: (1)
|
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Oil (Bbl)
|
$ | 98.63 | $ | 73.20 | $ | 94.58 | $ | 73.73 | ||||||||
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Natural gas liquids (Bbl)
|
54.80 | 40.23 | 51.45 | 42.91 | ||||||||||||
|
Natural gas (Mcf)
|
4.20 | 4.16 | 4.10 | 4.66 | ||||||||||||
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Mcfe
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6.76 | 5.77 | 6.40 | 6.16 | ||||||||||||
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Average unit cost per Mcfe:
|
||||||||||||||||
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Production costs:
|
||||||||||||||||
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Lease operating expenses (2)
|
$ | 1.78 | $ | 2.18 | $ | 1.77 | $ | 2.08 | ||||||||
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Production taxes
|
0.31 | 0.24 | 0.29 | 0.30 | ||||||||||||
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Total
|
2.09 | 2.42 | 2.06 | 2.38 | ||||||||||||
|
Asset retirement obligations accretion expense
|
0.10 | 0.11 | 0.10 | 0.10 | ||||||||||||
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Depreciation, depletion and amortization
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1.83 | 1.97 | 1.80 | 2.02 | ||||||||||||
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General and administrative expenses
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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)
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|
(In $ thousands, except number of units)
|
|
June 30, 2011
|
December 31, 2010
|
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ASSETS
|
||||||||
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Current assets:
|
||||||||
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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 | ||||||
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Long-term derivative asset
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26,576 | 51,497 | ||||||
|
Other assets
|
7,533 | 1,885 | ||||||
|
Total assets
|
$ | 1,466,821 | $ | 1,486,757 | ||||
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LIABILITIES AND OWNERS’ EQUITY
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||||||||
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Current liabilities:
|
||||||||
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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 | ||||||
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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
|
Six Months Ended
|
|||||||||||||||
|
June 30,
|
June 30,
|
|||||||||||||||
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2011
|
2010
|
2011
|
2010
|
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|
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:
|
||||||||||||||||
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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 | - | ||||||
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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 | ||||||
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Long-term liabilities
|
- | (734 | ) | |||||
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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
|
Six Months Ended
|
|||||||||||||||
|
June 30,
|
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
|
(MmmBtu
|
||||||||||||||||||||||
|
/Mbbls)
|
/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 | ||||||||||||||
| 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 | |||||||||||||||||||
|
Notional
Amount |
Fixed
Rate
|
||||||||||||||||||||||
|
Interest Rate Swap Agreements
|
(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 | % | ||||||||||||||||||||
EV Energy Partners, L.P., Houston
Michael E. Mercer, 713-651-1144
http://www.evenergypartners.com