SOURCE: EV Energy Partners, L.P.

EV Energy Partners, L.P.

March 01, 2011 06:20 ET

EV Energy Partners Announces Full Year and Fourth Quarter 2010 Results, 2010 Year End Proved Reserves, 2011 Guidance and Updated Hedge Positions

HOUSTON, TX--(Marketwire - March 1, 2011) - EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the full year and fourth quarter 2010, its year end 2010 proved reserves and the filing of its Form 10-K with the Securities and Exchange Commission. In addition, EVEP announced 2011 guidance and an update of its commodity hedge positions presented in the Hedge Summary Table at the end of this release.

Full Year 2010 Results

Adjusted EBITDAX and distributable cash flow for 2010 were $148.1 million and $94.2 million, increases of 12 percent and 24 percent, respectively, over 2009 primarily due to acquisitions made in 2010 as well as higher realized oil and natural gas prices. Adjusted EBITDAX and distributable cash flow are described in the attached table under "Non-GAAP Measures."

Production for 2010 was 19.5 Bcf of natural gas, 679 MBbls of oil and 728 MBbls of natural gas liquids, or 27.9 billion cubic feet equivalents (Bcfe). This represents a 15 percent increase over 2009 production of 24.2 Bcfe, primarily due to acquisitions in 2010.

For 2010, EVEP reported net income of $106.1 million. Included in net income were $3.0 million of non-cash net 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 related to acquisitions completed during 2010. We also recognized 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. For 2009, EVEP reported net income of $1.4 million. Included in 2009 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.

Fourth Quarter 2010 Results

Adjusted EBITDAX for the fourth quarter of 2010 was $41.6 million, a 21 percent increase over the fourth quarter of 2009 and a 12 percent increase over the third quarter of 2010. Distributable cash flow for the fourth quarter of 2010 was $26.8 million, a 26 percent increase over the fourth quarter of 2009 and an 11 percent increase over the third quarter of 2010.

For the fourth quarter of 2010, EVEP produced 6.0 Bcf of natural gas, 202 MBbls of oil and 187 MBbls of natural gas liquids, or 8.3 Bcfe. This is a 34 percent increase over fourth quarter 2009 production of 6.2 Bcfe, primarily due to production from our 2010 Appalachian Basin and Mid-Continent region acquisitions. Production increased by 19 percent from third quarter 2010 production of 7.0 Bcfe, primarily due to production from our Mid-Continent region acquisition closed at the end of the third quarter of 2010.

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 non-cash net 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 related to our acquisitions completed during the quarter. For the fourth quarter of 2009, EVEP reported a net loss of $2.5 million which included $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.

The $31.6 million non-cash net unrealized loss on commodity and interest rate derivatives for the fourth quarter of 2010 was primarily due to the increase in future oil prices that occurred from September 30, 2010 to December 31, 2010 and the effect of such increased prices on the mark-to-market valuation of EVEP's outstanding derivatives which extend through 2014.

John Walker, Chairman and CEO said, "We are pleased with our results for the quarter and for 2010. During the year we completed over $550 million of acquisitions, adding significantly to our Appalachian Basin and Mid-Continent region assets and establishing a new core area with our Barnett Shale acquisition. With these acquisitions, we increased our proved reserves over year-end 2009 by 124 percent, and at an attractive reserve replacement cost of $1.23 per mcfe. In addition, we are evaluating the potential of our acreage in the developing Utica/Point Pleasant play. EVEP has approximately 150,000 net held-by-production acres, primarily in Ohio, that could be prospective for the Utica/Point Pleasant and also owns overriding royalty interests on approximately 80,000 net acres. However, until horizontal wells have been drilled and tested this summer, it is not possible to properly assess the full potential of the play."

Year End 2010 Estimated Net Proved Reserves

EVEP's year end 2010 estimated net proved reserves were 817.3 Bcfe, a 123.5 percent increase over year end 2009 estimated net proved reserves, primarily due to acquisitions completed during 2010. Approximately 70.4 percent were natural gas, 9.5 percent were oil and 20.1 percent were natural gas liquids. In addition, 70.7 percent were categorized as proved developed. Our reserve replacement cost for 2010 was $1.23 per mcfe. Reserve Replacement cost is our cost incurred in oil and natural gas property acquisition and development activities divided by the sum of extensions and discoveries, purchases of minerals in place, and revisions of previous estimates of our estimated net proved reserves.

At December 31, 2010, the present value of future net pre-tax cash flows discounted at 10 percent was $1,026.5 million and the standardized measure of our estimated net proved reserves was $1,020.2 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 percent. 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. The prices used in determining our estimated net proved reserves at December 31, 2010, were $79.43 per Bbl of oil and $4.37 per MMBtu of natural gas.

                                                              Natural Gas
                               Natural   Crude Oil   NGL's    Equivalents
                               Gas (Bcf) (MMBbls)  (MMBbls)      (Bcfe)
                               --------- --------- --------- --------------
Barnett Shale                      218.5       0.1      15.2          310.0
Appalachia                          95.2       4.7         -          123.5
Mid-Continent                       58.3       2.8       0.8           79.7
San Juan                            43.1       1.3       3.8           73.8
Monroe                              64.7         -         -           64.7
Permian                             23.9       0.9       5.7           63.4
Central and East Texas              23.6       3.1       2.0           54.3
Michigan                            47.9         -         -           47.9
                               --------- --------- --------- --------------
Total Proved Reserves              575.2      12.9      27.5          817.3

Proved Developed Reserves          416.8      10.9      16.0          578.0

2011 Guidance

                                          1st Qtr 2011      2nd Qtr 2011
                                        ----------------  ----------------
Net Production:
 Natural Gas (MMcf)                      6,900  -  7,350   7,200  -  7,900
 Crude Oil (MBbls)                         190  -    215     195  -    215
 Natural Gas Liquids (MBbls)               260  -    290     285  -    315
Total Mmcfe                              9,600  - 10,380  10,080  - 11,080

Average Daily Production (Mmcfe/d)       106.7  -  115.3   110.8  -  121.8

Average Price Differential vs NYMEX
 Natural Gas (% of NYMEX Natural Gas)       92% -     96%     92% -     96%
 Crude Oil (% of NYMEX Crude Oil)           92% -     96%     92% -     96%
 Natural Gas Liquids (% of NYMEX Crude
  Oil)                                      44% -     50%     44% -     50%

 Transportation Margin ($ thous) (a)       350  -    400     350  -    400

Expenses:
Operating Expenses:
 LOE and other ($ thous)                15,850  - 17,450  16,350  - 18,150
 Production Taxes (as % of revenue)        4.4% -    4.8%    4.4% -    4.8%

General and administrative expenses ($
 thous) (b)                              4,500  -  5,500   4,500  -  5,500

Capital Expenditures ($ thous) (c)      13,000  - 17,000  15,000  - 19,000


                                           3rd Qtr 2011      4th Qtr 2011
                                        ----------------  ----------------
Net Production:
 Natural Gas (MMcf)                      7,450  -  8,250   7,650  -  8,450
 Crude Oil (MBbls)                         200  -    220     200  -    220
 Natural Gas Liquids (MBbls)               295  -    335     300  -    340
Total Mmcfe                             10,420  - 11,580  10,650  - 11,810

Average Daily Production (Mmcfe/d)       113.3  -  125.9   115.8  -  128.4

Average Price Differential vs NYMEX
 Natural Gas (% of NYMEX Natural Gas)       92% -     96%     92% -     96%
 Crude Oil (% of NYMEX Crude Oil)           92% -     96%     92% -     96%
 Natural Gas Liquids (% of NYMEX Crude
  Oil)                                      44% -     50%     44% -     50%

 Transportation Margin ($ thous) (a)       350  -    400     350  -    400

Expenses:
Operating Expenses:
 LOE and other ($ thous)                16,350  - 18,150  16,350  - 18,150
 Production Taxes (as % of revenue)        4.4% -    4.8%    4.4% -    4.8%

General and administrative expenses ($
 thous) (b)                              4,500  -  5,500   4,500  -  5,500

Capital Expenditures ($ thous) (c)      23,000  - 29,000  12,000  - 16,000

(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. Does not include any
     future acquisition related due diligence or 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 2010 Form 10-K, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.

Also available for download on our website by March 11, 2011 will be unitholders' Schedule K-1's for the tax year 2010. For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at (800)-973-7551.

Conference Call

As announced on February 25, 2011, EV Energy Partners, L.P. will host an investor conference call on March 1, 2011, at 9:30 a.m. Eastern Time (8:30 a.m. Central). Investors interested in participating in the call may dial (480)-629-9722 (quote conference ID 4419691) at least 5 minutes prior to the start time, or may listen live over the internet through the investor relations section of the EVEP website at http://www.evenergypartners.com. Financial results will also be posted in the investor relations section on the website.

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  Twelve Months Ended
                                       December 31,        December 31,
                                    ------------------- -------------------
                                      2010      2009      2010      2009
                                    --------- --------- --------- ---------
Production data:
 Oil (MBbls)                              202       128       679       514
 Natural gas liquids (MBbls)              187       188       728       768
 Natural gas (MMcf)                     5,958     4,288    19,486    16,519
                                    --------- --------- --------- ---------
 Net production (MMcfe)                 8,295     6,184    27,933    24,210
Average sales price per unit :
 Oil (Bbl)                          $   79.57 $   71.92 $   74.78 $   56.17
 Natural gas liquids (Bbl)              46.54     41.09     42.64     31.08
 Natural gas (Mcf)                       3.75      4.15      4.30      3.71
 Mcfe                                    5.69      5.61      5.93      4.71
Average unit cost per Mcfe:
 Production costs:
  Lease operating expenses          $    1.78 $    1.69 $    1.92 $    1.71
  Production taxes                       0.26      0.30      0.28      0.25
                                    --------- --------- --------- ---------
  Total                                  2.04      1.99      2.20      1.96
Asset retirement obligations
 accretion expense                       0.13      0.09      0.11      0.08
Depreciation, depletion and
 amortization                            2.01      2.06      1.98      2.15
General and administrative expenses      0.81      0.92      0.83      0.77




Consolidated Balance Sheets
(in $ thousands)
                                                December 31,  December 31,
                                                    2010          2009
                                                ------------  ------------
                   ASSETS
Current assets:
 Cash and cash equivalents                      $     23,127  $     18,806
 Accounts receivable:
  Oil, natural gas and natural gas liquids
   revenues                                           27,742        14,599
  Related party                                            -         2,881
  Other                                                  441         1,034
 Derivative asset                                     55,100        26,733
 Other current assets                                  1,158           625
                                                ------------  ------------
  Total current assets                               107,568        64,678
Oil and natural gas properties, net of
 accumulated depreciation, depletion and
 amortization; December 31, 2010, $176,897;
 December 31, 2009, $121,970                       1,324,240       771,752
Other property, net of accumulated depreciation
 and amortization; December 31, 2010, $465;
 December 31, 2009, $319                               1,567           742
Long-term derivative asset                            51,497        68,549
Other assets                                           1,885         1,984
                                                ------------  ------------
Total assets                                    $  1,486,757  $    907,705
                                                ============  ============

         LIABILITIES AND OWNERS' EQUITY
Current liabilities:
 Accounts payable and accrued liabilities
  Third party                                   $     20,678  $     10,310
  Related party                                          182             -
 Derivative liability                                  1,943         1,543
                                                ------------  ------------
  Total current liabilities                           22,803        11,853

Asset retirement obligations                          67,175        42,533
Long-term debt                                       619,000       302,000
Other long-term liabilities                            3,048         3,212
Long-term derivative liability                           784           676

Commitments and contingencies

Owners' equity
 Common unitholders                                  779,327       548,160
 General partner interest                             (5,380)         (729)
                                                ------------  ------------
  Total owners' equity                               773,947       547,431
                                                ------------  ------------
Total liabilities and owners' equity            $  1,486,757  $    907,705
                                                ============  ============


Consolidated Statements of Operations
(in $ thousands, except per unit data)


                                 Three Months Ended   Twelve Months Ended
                                    December 31,          December 31,
                                --------------------  --------------------
                                  2010       2009       2010       2009
                                ---------  ---------  ---------  ---------
Revenues:
 Oil, natural gas and natural
  gas liquids revenues          $  47,184  $  34,705  $ 165,738  $ 114,066
 Transportation and
  marketing-related revenues        1,228      1,445      5,780      7,846
                                ---------  ---------  ---------  ---------
  Total revenues                   48,412     36,150    171,518    121,912
                                ---------  ---------  ---------  ---------
Operating costs and expenses:
 Lease operating expenses          14,795     10,420     53,736     41,495
 Cost of purchased natural gas        906      1,078      4,353      4,509
 Dry hole and exploration costs       182          0        417          -
 Production taxes                   2,191      1,840      7,867      5,983
 Asset retirement obligations
  accretion expense                 1,109        527      3,153      2,035
 Depreciation, depletion and
  amortization                     16,685     12,744     55,221     52,048
 General and administrative
  expenses                          6,750      5,686     23,313     18,556
 Gain on sales of oil and
  natural gas properties              (39)         0    (40,656)         -
                                ---------  ---------  ---------  ---------
  Total operating costs and
   expenses                        42,579     32,295    107,404    124,626
                                ---------  ---------  ---------  ---------
Operating income (loss)             5,833      3,855     64,114     (2,714)
Other (expense) income, net:
 Realized gains on derivatives,
  net                              13,871     13,783     49,042     68,984
 Unrealized (losses) gains on
  derivatives, net                (31,572)   (17,261)     2,994    (51,665)
 Interest expense                  (2,751)    (2,412)   (10,442)   (12,321)
 Other income (expense), net          174       (309)       628       (626)
                                ---------  ---------  ---------  ---------
  Total other (expense) income,
   net                            (20,278)    (6,199)    42,222      4,372
                                ---------  ---------  ---------  ---------
(Loss) income before income
 taxes                            (14,445)    (2,344)   106,336      1,658
Income taxes                          (43)      (127)      (285)      (248)
                                ---------  ---------  ---------  ---------
Net (loss) income               $ (14,488) $  (2,471) $ 106,051  $   1,410
                                =========  =========  =========  =========
General partner's interest      $   2,338  $   1,941  $  11,938  $   7,040
                                =========  =========  =========  =========
Limited partners' interest      $ (16,826) $  (4,412) $  94,113  $  (5,630)
                                =========  =========  =========  =========
Net (loss) income per limited
 partner unit:
 Basic                          $   (0.55) $   (0.19) $    3.35  $   (0.29)
 Diluted                        $   (0.55) $   (0.19) $    3.34  $   (0.29)
Weighted average limited
 partner units outstanding:
 Basic                             30,630     23,583     28,095     19,302
 Diluted                           30,630     23,583     28,162     19,302

Distributions declared per unit $   0.759  $   0.755  $    3.03  $    3.01




Consolidated Statements of Cash Flows
(in $ thousands)
                                                   Twelve        Twelve
                                                Months Ended  Months Ended
                                                December 31,  December 31,
                                                    2010          2009
                                                ------------  ------------

Cash flows from operating activities:
 Net income                                     $    106,051  $      1,410
 Adjustments to reconcile net income to net
  cash flows provided by operating activities:
  Dry hole costs                                         170             -
  Asset retirement obligations accretion
   expense                                             3,153         2,035
  Depreciation, depletion and amortization            55,221        52,048
  Equity-based compensation                            5,043         3,659
  Gain on sales of oil and natural gas
   properties                                        (40,656)            -
  Unrealized (gains) losses on derivatives, net       (2,994)       51,665
  Amoritization of deferred loan costs                   564           799
  Other                                                 (169)          544
  Changes in operating assets and liabilities:
   Accounts receivable                                (9,320)        3,955
   Other current assets                                2,215           214
   Accounts payable and accrued liabilities            4,514        (2,126)
   Deferred revenues                                       -        (4,120)
   Long-term liabilities                                (734)            -
   Other, net                                           (705)         (558)
                                                ------------  ------------
Net cash flows provided by operating activities      122,353       109,525
                                                ------------  ------------
Cash flows from investing activities:
 Acquisitions of oil and natural gas properties     (568,433)      (39,646)
 Development of oil and natural gas properties       (26,525)      (14,271)
 Proceeds from sales of oil and natural gas
  properties                                          44,399             -
                                                ------------  ------------
Net cash flows used in investing activities         (550,559)      (53,917)
                                                ------------  ------------
Cash flows from financing activities:
 Long-term debt borrowings                           543,000        20,000
 Repayments of long-term debt borrowings            (226,000)     (185,000)
 Proceeds from equity offerings                      204,965       149,038
 Offering costs                                         (306)         (484)
 Loan costs incurred                                    (465)          (44)
 Contributions from general partner                    4,267         3,077
 Distributions to partners                           (92,934)      (65,017)
                                                ------------  ------------
Net cash flows provided by (used in) financing
 activities                                          432,527       (78,430)
                                                ------------  ------------

Increase (decrease) in cash and cash
 equivalents                                           4,321       (22,822)
Cash and cash equivalents - beginning of period       18,806        41,628
                                                ------------  ------------
Cash and cash equivalents - end of period       $     23,127  $     18,806
                                                ============  ============

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 losses (gains) losses on derivatives, amortization of upfront premiums paid to enter into commodity price hedge agreements, non-cash equity compensation, (gain) on sales 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 (gains) losses on interest rate swaps, amortization of upfront premiums paid to enter into commodity price hedge agreements and estimated maintenance capital expenditures.

Adjusted EBITDAX 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 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 effect 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 EBITDA and Distributable Cash Flow
(in $ thousands)

                                 Three Months Ended   Twelve Months Ended
                                    December 31,          December 31,
                                --------------------  ---------------------
                                  2010       2009       2010        2009
                                ---------  ---------  ---------  ----------

Net (loss) income               $ (14,488) $  (2,471) $ 106,051  $    1,410
Add:
Income taxes                           43        127        285         248
Interest expense, net               2,746      2,405     10,398      12,189
Realized losses on interest
 rate swaps                         2,189      2,200      8,652       8,351
Depreciation, depletion and
 amortization                      16,685     12,744     55,221      52,048
Asset retirement obligation
 accretion expense                  1,109        527      3,153       2,035
Non-cash losses (gains) on
 commodity derivatives             31,572     17,261     (2,994)     51,665
Amortization of premiums on
 derivatives                            -        209          -         608
Non-cash equity compensation
 expense                            1,629      1,462      5,043       3,659
(Gain) on sales of oil and
 natural gas properties               (39)         -    (40,656)          -
Non-cash charges related to oil
 in tanks from 2009 and 2010
 Appalachian Basin acquisitions
 included in lease operating
 expense                                -          -      2,542           -
Dry hole and exploration costs        182          -        417           -
                                ---------  ---------  ---------  ----------
Adjusted EBITDAX                $  41,628  $  34,464  $ 148,112  $  132,213

Less:
Income taxes                           43        127        285         248
Cash interest expense, net          2,596      2,268      9,834      11,390
Realized losses on interest
 rate swaps                         2,189      2,200      8,652       8,351
Amortization of premiums on
 derivatives                            -        209          -         608
Estimated maintenance capital
 expenditures (1)                  10,037      8,348     35,167      35,360
                                ---------  ---------  ---------  ----------
Distributable Cash Flow         $  26,763  $  21,312  $  94,174  $   76,256


(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 Since 09/30/2010 (as of February 28, 2011)


                                Swap      Swap      Collar   Collar  Collar
Period         Index          Volume     Price      Volume   Floor  Ceiling
--------   -------------- ------------  ------- ----------- ------- -------
Natural                      (Mmmbtu/              (Mmmbtu/
 Gas                           Mbbls)                Mbbls)
1Q 2011             NYMEX      1,443.0  $  4.95       279.3 $  5.93 $  6.82
2Q 2011             NYMEX      1,231.5  $  5.02       282.4 $  5.93 $  6.82
3Q 2011             NYMEX      1,061.0  $  5.14       285.5 $  5.93 $  6.82
4Q 2011             NYMEX        877.0  $  5.26       285.5 $  5.93 $  6.82

2011           NGPL TX/OK                           1,019.0 $  5.75 $  6.58

1H2012              NYMEX      1,820.0  $  5.02       846.8 $  6.22 $  6.70
                    NYMEX                             169.6 $  6.25 $  8.13
2H2012              NYMEX      1,288.0  $  5.07       856.2 $  6.22 $  6.70
                    NYMEX                             171.4 $  6.25 $  8.13

2013                NYMEX     13,322.5  $  5.26

Crude Oil
1Q 2011               WTI         39.9  $ 90.37        16.7 $ 88.00 $ 95.33
2Q 2011               WTI         35.8  $ 90.29        16.9 $ 88.00 $ 95.33
3Q 2011               WTI         29.3  $ 90.12        17.1 $ 88.00 $ 95.33
4Q 2011               WTI         23.7  $ 89.92        17.1 $ 88.00 $ 95.33

1Q 2012               WTI         95.6  $ 95.58        22.6 $ 82.50 $100.00
2Q 2012               WTI         86.5  $ 95.51        22.6 $ 82.50 $100.00
3Q 2012               WTI         82.8  $ 95.24        22.9 $ 82.50 $100.00
4Q 2012               WTI         73.6  $ 95.18        22.9 $ 82.50 $100.00

1Q 2013               WTI        126.0  $ 94.85
2Q 2013               WTI        122.9  $ 94.72
3Q 2013               WTI        119.6  $ 94.70
4Q 2013               WTI        115.0  $ 94.60

1 H2014               WTI        217.2  $ 96.41
2 H2014               WTI        379.6  $ 96.30

Ethane
             Mt. Belvieu
1Q 2011    (Non-TET)-OPIS        103.5  $ 25.20
             Mt. Belvieu
2Q 2011    (Non-TET)-OPIS        100.1  $ 22.16
             Mt. Belvieu
3Q 2011    (Non-TET)-OPIS         96.6  $ 20.32
             Mt. Belvieu
4Q 2011    (Non-TET)-OPIS         92.0  $ 19.79

Propane
             Mt. Belvieu
1Q 2011    (Non-TET)-OPIS         63.0  $ 53.19
             Mt. Belvieu
2Q 2011    (Non-TET)-OPIS         59.2  $ 49.20
             Mt. Belvieu
3Q 2011    (Non-TET)-OPIS         57.5  $ 49.36
             Mt. Belvieu
4Q 2011    (Non-TET)-OPIS         55.2  $ 50.20




Hedge Summary Table (as of February 28, 2011)

                                  Swap     Swap    Collar   Collar  Collar
Period             Index         Volume   Price    Volume   Floor   Ceiling
--------     ------------------ --------- ------- --------- ------- -------
                                 (Mmmbtu/          (Mmmbtu/
Natural Gas                        Mbbls)            Mbbls)
1Q 2011                   NYMEX   4,115.9 $  6.16     387.8 $  5.90 $  7.03
                      Dominion
                     Appalachia     225.0 $  8.69     270.0 $  9.00 $ 12.15
                El Paso Permian     225.0 $  9.30
                  Houston Ship
                        Channel                       315.0 $  8.25 $ 11.65
               MichCon Citygate                       405.0 $  8.70 $ 11.85
                     NGPL TX/OK                       251.3 $  5.75 $  6.58

2Q 2011                   NYMEX   3,934.2 $  6.25     392.1 $  5.90 $  7.03
                      Dominion
                     Appalachia     227.5 $  8.69     273.0 $  9.00 $ 12.15
                El Paso Permian     227.5 $  9.30
                  Houston Ship
                        Channel                       318.5 $  8.25 $ 11.65
               MichCon Citygate                       409.5 $  8.70 $ 11.85
                     NGPL TX/OK                       254.1 $  5.75 $  6.58

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

Jan-Aug 2014              NYMEX   1,215.0 $  7.06

                                     Swap    Swap    Collar  Collar  Collar
Period                    Index    Volume   Price    Volume   Floor Ceiling
--------     ------------------ --------- ------- --------- ------- -------
                                 (Mmmbtu/          (Mmmbtu/
Crude Oil                          Mbbls)            Mbbls)
1Q 2011                     WTI     116.4 $ 94.53     115.7 $105.66 $156.16
2Q 2011                     WTI     113.1 $ 94.68     117.0 $105.66 $156.16
3Q 2011                     WTI     107.5 $ 94.91     118.3 $105.66 $156.16
4Q 2011                     WTI     102.0 $ 95.12     118.3 $105.66 $156.16

1Q 2012                     WTI     167.0 $ 96.49     112.6 $104.53 $156.77
2Q 2012                     WTI     157.9 $ 96.50     113.9 $104.53 $156.77
3Q 2012                     WTI     155.0 $ 96.38     115.1 $104.53 $156.77
4Q 2012                     WTI     145.8 $ 96.43     115.1 $104.53 $156.77

1Q 2013                     WTI     252.0 $ 86.74
2Q 2013                     WTI     250.3 $ 86.53
3Q 2013                     WTI     248.4 $ 86.37
4Q 2013                     WTI     243.8 $ 86.17

1H 2014                     WTI     452.5 $ 89.52
2H 2014                     WTI     444.7 $ 94.33

Ethane
                           Mt.
              Belvieu(Non-TET)-
1Q 2011                   OPIS      103.5 $ 25.20
                           Mt.
             Belvieu(Non-TET)-
2Q 2011                    OPIS     100.1 $ 22.16
                           Mt.
             Belvieu(Non-TET)-
3Q 2011                    OPIS      96.6 $ 20.32
                           Mt.
             Belvieu(Non-TET)-
4Q 2011                    OPIS      92.0 $ 19.79

Propane
                           Mt.
             Belvieu(Non-TET)-
1Q 2011                    OPIS      63.0 $ 53.19
                           Mt.
             Belvieu(Non-TET)-
2Q 2011                    OPIS      59.2 $ 49.20
                           Mt.
             Belvieu(Non-TET)-
3Q 2011                    OPIS      57.5 $ 49.36
                           Mt.
             Belvieu(Non-TET)-
4Q 2011                    OPIS      55.2 $ 50.20

                                Notional   Fixed
                                  Amount    Rate
                                --------- -------
Interest Rate Swap Agreements   (in $mill)
January 2011 - July 2012            200.0   4.163%
January 2011 - Sept 2012             40.0   2.145%


                                   Swap     Swap
                                  Volume   Price
                                --------- --------
                                (Mmmbtu/
Basis Swaps                        Mbbls)
Discount (Premium)
 to NYMEX
                      Dominion
2011                 Appalachia     346.0 $ 0.1975
                      Columbia
2011                 Appalachia      94.5 $ 0.1500

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