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BRY > SEC Filings for BRY > Form 10-Q/A on 9-May-2013All Recent SEC Filings

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Form 10-Q/A for BERRY PETROLEUM CO


9-May-2013

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain significant factors that have affected aspects of our financial position and the results of operations during the periods included in the accompanying Condensed Financial Statements. The following discussion and analysis should be read in conjunction with the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited Financial Statements for the year ended December 31, 2012, included in our Annual Report on Form 10-K and the Condensed Financial Statements included elsewhere herein.

Our revenue, profitability and future growth rate depend on many factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices have been volatile and may fluctuate widely in the future. The following charts highlight the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2010:

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Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and natural gas reserves. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil prices may result in significant non-cash fair value losses being incurred on our oil derivatives, which could cause us to experience net losses when prices rise.

Steam costs are a significant variable component of our operating costs and fluctuate based on the amount of steam we inject and the price of natural gas used to generate steam. We benefit from lower natural gas prices as a consumer of natural gas in our California operations. In the Permian, Uinta, E. Texas and Piceance, we benefit from higher natural gas pricing as a producer of natural gas. In addition, production rates, labor and equipment costs, maintenance expenses and production taxes influence our operating costs. Our results of operations may fluctuate from period to period based on such factors.

LinnCo, LLC Merger

On February 20, 2013, the Company, Linn Energy, LLC (Linn), LinnCo, LLC (LinnCo), Linn Acquisition Company, LLC, a direct wholly owned subsidiary of LinnCo (LinnCo Merger Sub), Bacchus HoldCo, Inc., a direct wholly owned subsidiary of the Company (HoldCo), and Bacchus Merger Sub, Inc., a direct wholly owned subsidiary of HoldCo (Bacchus Merger Sub), entered into a definitive Agreement and Plan of Merger (the "Merger Agreement"), pursuant to which LinnCo agreed to acquire the Company in an all-stock transaction in which the Company's stockholders would receive 1.25 shares representing limited liability company interests in LinnCo (LinnCo Shares) for each share of the Company's common stock.


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The transaction will occur through multiple steps. First, the Company will engage in a holding company merger (the HoldCo Merger) involving HoldCo and Bacchus Merger Sub. In the HoldCo Merger, Bacchus Merger Sub will merge with and into the Company, with the Company surviving as a wholly owned subsidiary of HoldCo, and each issued and outstanding share of the Company's Class A common stock and Class B common stock will convert into the right to receive one equivalent share of Class A common stock and one equivalent share of Class B common stock, respectively, of HoldCo.

Second, promptly after the HoldCo Merger, the Company will be converted into a limited liability company. Third, promptly following such conversion, HoldCo will be merged with and into LinnCo Merger Sub, with LinnCo Merger Sub surviving as the surviving company (the LinnCo Merger). In the LinnCo Merger, each share of Holdco's Class A common stock and each share of Holdco's Class B common stock will be converted into 1.25 LinnCo Shares.

Finally, promptly following the LinnCo Merger, LinnCo will contribute all of the outstanding equity interests in LinnCo Merger Sub (and therefore also its indirect ownership interest in the Company) to Linn (the "Contribution") in exchange for the issuance to LinnCo (the "Issuance") of newly issued Linn common units. The number of Linn common units to be issued to LinnCo in the Issuance will be equal to the greater of (i) the aggregate number of LinnCo Shares issued in the LinnCo Merger and (ii) the number of Linn common units required to cause LinnCo to own no less than one-third of all of the outstanding Linn common units following the Contribution. In addition, for three years following the closing, Linn will pay to LinnCo additional cash distributions in the amount of $6 million per year.

The closing of the transactions is subject to customary closing conditions, including approval of the Merger Agreement and the transactions contemplated thereby by the stockholders of the Company and the holders of the shares of LinnCo and Linn, receipt of certain opinions by the parties with respect to the tax-free nature of the transactions, and other customary conditions.

On March 1, 2013, a purported stockholder class action captioned Nancy P. Assad Trust v. Berry Petroleum Company, et al. was filed in the United States District Court for the District of Colorado. The case was dismissed by the Court on March 20, 2013 for lack of subject matter jurisdiction, and refiled in the District Court for the City and County of Denver, Colorado on March 21, 2013, Case No. 2013CV031365. On April 5, 2013, the plaintiff filed an amended complaint alleging that the individual Company director defendants breached their fiduciary duties in connection with the proposed merger transaction with Linn and LinnCo by engaging in an unfair sales process that resulted in an unfair price for the Company, and that the entity defendants aided and abetted those breaches of fiduciary duty. The amended complaint seeks a declaration that the proposed merger transactions are unlawful and unenforceable, an order directing the individual director defendants to comply with their fiduciary duties, an injunction against consummation of the merger transactions or, in the event they are so completed, rescission of the transactions, an award of fees and costs, including attorneys' and experts' fees and expenses, and other relief. On April 12, 2013, a second purported stockholder class action captioned David S. Hall v. Berry Petroleum Company, et al. was filed in the Court of Chancery of the State of Delaware, C.A. No. 8476-VCG. The plaintiff in this case makes allegations, and seeks relief similar to the allegations made and relief sought in the Assad case.
A response has not yet been filed with respect to either complaint. However, the Company believes the claims relating to the merger are without merit, and intends to defend such actions vigorously. Notable First Quarter 2013 Items

Increased oil production by 2% from the fourth quarter of 2012

Generated discretionary cash flow of $133.9 million from production of 39,676 BOE/D, of which 79% was oil(1)

Generated an operating margin of $48.80 per BOE, supported by sales of our California heavy oil at a $10.18 average premium to WTI during the quarter(1)

Average daily production from our Diatomite properties increased 7% from the fourth quarter of 2012

Production from our North Midway-Sunset-New Steam Floods (NMWSS-NSF) properties, which include McKittrick, averaged 2,355 BOE/D, an 11% increase from the fourth quarter of 2012

Production from our Permian properties averaged 8,105 BOE/D, a 2% increase from the fourth quarter of 2012

Drilled 20 Uinta wells, 10 Permian wells and 44 Diatomite wells



(1) Discretionary cash flow and operating margin are considered non-GAAP performance measures and reference should be made to "Reconciliation of Non-GAAP Measures" for further explanation as well as reconciliations to the most directly comparable GAAP measures.


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Results of Operations.

In the first quarter of 2013, we reported net earnings of $32.4 million, or $0.58 per diluted share, and net cash flows from operations of $91.7 million. Net earnings in the first quarter of 2013 included a loss on derivatives of $1.9 million resulting from non-cash changes in fair values, lease write offs of $1.5 million and $1.3 million of professional fees associated with the pending LinnCo merger, in each case net of income taxes.

Operating Data.

The following table sets forth selected operating data for the three months
ended:

                                                                                            December 31,
                                         March 31, 2013     %      March 31, 2012     %         2012        %
Heavy oil production (BOE/D)                   19,566        50           17,005       49       19,058       48
Light oil production (BOE/D)                   11,588        29            8,091       24       11,591       30
Total oil production (BOE/D)                   31,154        79           25,096       73       30,649       78
Natural gas production (Mcf/D)                 51,132        21           56,105       27       53,106       22
Total (BOE/D)(1)                               39,676       100           34,447      100       39,500      100
Oil and natural gas, per BOE:
Average realized sales price            $       75.27             $        74.33            $    70.51
Average sales price including cash
derivative settlements                  $       75.95             $        74.44            $    72.47
Oil, per BOE:
Average WTI price                       $       94.36             $       103.03            $    88.23
Price sensitive royalties(2)                    (2.81 )                    (4.24 )               (2.65 )
Location differential and other(3)              (1.25 )                    (1.48 )                0.79
Oil derivatives non-cash
amortization(4)                                  0.89                      (1.14 )               (1.03 )
Oil revenue                             $       91.19             $        96.17            $    85.34
Add: Oil derivatives non-cash
amortization(4)                                     -                       1.14                  1.03
Oil derivative cash settlements(5)              (0.89 )                    (3.08 )                1.57
Average realized oil price              $       90.30             $        94.23            $    87.94
Natural gas price:
Average Henry Hub price per MMBtu       $        3.34             $         2.72            $     3.41
Conversion to Mcf                                0.22                       0.18                  0.24
Natural gas derivatives non-cash
amortization(4)                                     -                      (0.01 )                   -
Location differential and other                 (0.09 )                    (0.30 )               (0.14 )
Natural gas revenue per Mcf             $        3.47             $         2.59            $     3.51
Add: Natural gas derivatives non-cash
amortization(4)                                     -                       0.01                     -
Natural gas derivative cash
settlements(5)                                  (0.01 )                     0.92                 (0.03 )
Average realized natural gas price per
Mcf                                     $        3.46             $         3.52            $     3.48


__________________________________


(1) Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.

(2) Our Formax property in SMWSS-Steam Floods is subject to a price-sensitive royalty burden. The royalty is 53% of the amount of the heavy oil posted price above the 2013 base price of $17.78 per barrel as long as we maintain a minimum steam injection level. We met the steam injection level in the first quarter of 2013 and expect to meet the requirement going forward. The base price escalates at 2% annually and will be $18.14 in 2014.

(3) In California, the per barrel oil posting differential at March 31, 2013 was $9.10, ranged from $9.10 to $11.02 during the first quarter of 2013 and averaged $10.18 during the first quarter of 2013. In Utah, the per barrel oil posting differential at March 31, 2013 was ($16.50), ranged from ($14.50) to ($16.50) during the first quarter of 2013 and averaged ($15.65) during the first quarter of 2013.

(4) Non-cash amortization of AOCL resulting from discontinuing hedge accounting effective January 1, 2010. Recorded in the Condensed Statements of Operations under the caption oil and natural gas sales. At December 31, 2012, the entire balance of AOCL had been reclassified into earnings.

(5) Cash settlements on derivatives are recorded in the Condensed Statements of Operations under the caption realized and unrealized loss on derivatives, net.


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The following table sets forth results of operations (in thousands except per share data) for the three month periods ended:

                           March 31,       March 31,      1Q12 to 1Q13       December 31,      4Q12 to 1Q13
                             2013            2012            Change              2012             Change
Oil sales                $   250,777     $   220,452            14  %      $      231,766             8  %
Natural gas sales             15,995          13,201            21  %              17,145            (7 )%
Total oil and natural
gas sales                $   266,772     $   233,653            14  %      $      248,911             7  %
Electricity sales              7,589           5,980            27  %               8,586           (12 )%
Natural gas marketing          2,027           1,859             9  %               2,253           (10 )%
Gain on sale of assets            23           1,763           (99 )%                  12            92  %
Interest and other
income, net                      475             747           (36 )%                 307            55  %
Total revenues and other
income                   $   276,886     $   244,002            13  %      $      260,069             6  %
Net earnings             $    32,434     $    33,898            (4 )%      $       38,499           (16 )%
Diluted earnings per
share                    $      0.58     $      0.61            (5 )%      $         0.69           (16 )%

Oil and Natural Gas Sales.

Oil and natural gas sales increased $33.1 million, or 14%, to $266.8 million in the first quarter of 2013 compared to the same period in 2012. The increase was primarily due to an increase in oil sales volumes between periods. Our oil sales volume increased 21% in the first quarter of 2013 compared to the first quarter of 2012, while our natural gas sales volumes decreased 10%. The oil sales volume increase was primarily due to increased oil production from each of our oil properties. Permian oil production in the first quarter of 2013 increased 2,065 BOE/D, or 44%, from the same period in 2012, Uinta oil production increased 1,525 BOE/D, or 49%, between periods, Diatomite oil production in the first quarter of 2013 increased 1,430 BOE/D, or 53%, from the same period in 2012, oil production for NMWSS-NSF increased 845 BOE/D, or 56%, between periods and South Midway-Sunset-Steam Floods (SMWSS-Steam Floods) oil production increased 285 BOE/D, or 2%, between periods. The decrease in natural gas sales volumes was primarily due to expected production declines from our E. Texas and Piceance properties, partially offset by increased natural gas production from our Permian and Uinta properties.

Oil and natural gas sales increased $17.9 million, or 7%, to $266.8 million in the first quarter of 2013 compared to the fourth quarter of 2012. The increase was primarily due to a 7% increase in the average realized sales price between periods, primarily due to an increase in oil sales volumes as a percentage of total sales volumes. In addition, oil sales volumes increased 2% in the first quarter of 2013 compared to the fourth quarter of 2012, while natural gas sales volumes decreased 6% between periods. The oil sales volume increase was primarily due to increased oil production from all of our oil properties with the exception of SMWSS-Steam Floods, which declined marginally as expected, and the Uinta, which was impacted by refinery constraints in the Utah region. Diatomite oil production increased 260 BOE/D, or 7%, between periods, NMWSS-NSF oil production increased 225 BOE/D, or 11%, from the fourth quarter of 2012, and Permian oil production increased 175 BOE/D, or 3%, between periods. The decrease in natural gas sales volumes was primarily due to expected field decline in E. Texas and the Piceance.


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Electricity Sales.

The following table sets forth selected results of operations for the periods
ended:

                                                                  Three Months Ended
                                                      March 31,       March 31,      December 31,
                                                        2013            2012             2012
Electricity
Electricity sales (in thousands)                    $     7,589     $     5,980     $       8,586
Operating costs (in thousands)                      $     5,296     $     5,017     $       5,975
Electric power produced (MWh/D)                           2,036           2,089             2,112
Electric power sold (MWh/D)                               1,851           1,935             1,917
Average sales price per MWh                         $     44.77     $     33.96     $       41.30
Fuel gas cost per MMBtu (including transportation)  $      3.55     $      2.71     $        3.51
Estimated natural gas volumes consumed to produce
electricity (MMBtu/D)(1)                                 14,726          15,197            15,987


_______________________________________


(1) Estimate is based on the historical allocation of fuel costs to electricity.

Electricity sales in the first quarter of 2013 increased 27% compared to the first quarter of 2012 primarily due to a 32% increase in the average sales price of electricity, partially offset by a 4% decrease in electric power sold. Electricity operating costs in the first quarter of 2013 increased 6% compared to the first quarter of 2012 largely due to a 31% increase in fuel gas cost, partially offset by a 3% decrease in electric power produced. Electricity sales decreased 12% in the first quarter of 2013 compared to the fourth quarter of 2012. Electricity sales in the fourth quarter of 2012 included a retroactive payment adjustment for capacity of $1.3 million from one of our electricity customers. As a result of our previously disclosed global settlement with various parties that became effective on November 23, 2011, we received retroactive payments for firm capacity that had been originally paid at "as available" capacity rates, and these payments represent the difference in rates over the disputed period. Excluding the retroactive payment adjustments, electricity sales in the first quarter of 2013 would have increased 5% compared to the fourth quarter of 2012 primarily due to an 8% increase in the average sales price of electricity partially offset by a 3% decrease in electric power sold. Electricity operating costs in the first quarter of 2013 decreased 11% compared to the fourth quarter of 2012 largely due to an 8% decrease in fuel gas volumes purchased.

Electricity Sales Contracts. We sell electricity produced by our cogeneration facilities under long-term contracts approved by the California Public Utilities Commission (CPUC) to two California investor owned utilities (IOUs): Southern California Edison Company (Edison) and Pacific Gas and Electric Company (PG&E). Under these power purchase agreements (PPAs), we are paid an energy payment that reflects the utility's Short Run Avoided Cost (SRAC) of energy plus a capacity payment that reflects a recovery of capital expenditures that would otherwise have been made by the utility. Beginning in 2015, the energy prices we will be paid under the contracts for our Cogen 18 and Cogen 38 facilities will be based on market prices for electricity in California.

Our legacy PPAs for our Cogen 42 facilities expired in May 2012, at which time a transition PPA with Edison became effective. The transition PPA will terminate on July 1, 2014, upon the effectiveness of a seven-year contract for our Cogen 42 facilities pursuant to a competitive solicitation (the RFO PPA).

Our legacy PPA for our Cogen 38 facility expired in March 2012, at which time a transition PPA with PG&E became effective. We intend to participate in future CHP competitive solicitations for the sale of energy and capacity from our Cogen 38 facility, although there is no assurance we will be successful in entering into a new RFO PPA for this facility. Our transition PPA with PG&E will remain in effect until June 2015.

Our legacy PPA with PG&E for our Cogen 18 facility terminated on September 30, 2012 and was replaced with a new Public Utilities Regulatory Policy Act of 1978, as amended (PURPA) PPA with PG&E, effective October 1, 2012, for a term of seven years. Because the rated capacity of our Cogen 18 facility is less than 20 MW, it continues to be eligible for PPAs pursuant to PURPA.

Under the PURPA PPA for our Cogen 18 facility and the transition PPAs for our Cogen 38 and Cogen 42 facilities, we will be paid the CPUC-determined SRAC energy price and a combination of firm and "as-available" capacity payments. Under the RFO PPA for our Cogen 42 facility, we will be paid a negotiated energy and capacity price stipulated in the contract.


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The following table summarizes our cogeneration facilities and related contract information as of March 31, 2013:

Facility   Type of Contract(1)   Purchaser   Contract Expiration
Cogen 42       Transition         Edison         Jul 2014(1)
Cogen 18          PURPA            PG&E           Sept 2019
Cogen 38       Transition          PG&E          Jun 2015(2)


__________________________________


(1) A new 7-year RFO PPA with Edison will be effective on July 1, 2014.

(2) We anticipate the current contract will be replaced by a long-term contract with a term of up to seven years pursuant to a future competitive solicitation.

Natural Gas Marketing.

We have long-term firm transportation contracts on the Rockies Express, Wyoming Interstate Company, and Ruby pipelines, each with a total average capacity of 35,000 MMBtu/D. Demand charges for our capacity are reflected in operating costs-oil and natural gas production in our Condensed Statements of Operations. Our current production is insufficient to fully utilize this capacity. To optimize our remaining capacity, we purchase third-party natural gas at the market rate in our producing areas and utilize FERC-approved asset management agreements. Sales and purchases of third-party natural gas are recorded under natural gas marketing in the revenues and expenses sections of the Condensed Statements of Operations, respectively.
The pre-tax net earnings of natural gas marketing operations for the three months ended March 31, 2013 and 2012 were $0.1 million and $0.1 million, respectively.

Gain on Sale of Assets.

In the first quarter of 2012, we recorded a $1.6 million gain in conjunction with the sale of our Nevada Assets. These gains were recorded in the Condensed Statements of Operations under the caption gain on sale of assets.

Oil and Natural Gas Operating and Other Expenses.

The following table sets forth our operating expenses for the three months
ended:

                                       Amount Per BOE                                Amount (in thousands)
                         March 31,       March 31,      December 31,      March 31,      March 31,       December 31,
                           2013            2012             2012             2013           2012             2012
Operating costs-oil
and natural gas
production(1)          $     24.13     $     17.30     $       23.35     $   86,148     $   54,221     $       84,862
Production taxes              3.02            3.40              2.57         10,784         10,658              9,326
DD&A-oil and natural
gas production               19.07           15.30             18.44         68,084         47,956             67,023
General and
administrative                6.24            5.66              5.03         22,278         17,741             18,293
Interest expense              6.91            6.41              5.97         24,687         20,104             21,690
Total                  $     59.37     $     48.07     $       55.36     $  211,981     $  150,680     $      201,194


_______________________________________


(1) Operating costs-oil and natural gas production includes firm transportation costs of $7.7 million and $7.0 million for the three months ended March 31, 2013 and 2012, respectively, and $7.1 million for the three months ended December 31, 2012.

Operating costs-oil and natural gas production in the first quarter of 2013 were $86.1 million, or $24.13 per BOE, compared to $54.2 million, or $17.30 per BOE, in the first quarter of 2012 and $84.9 million, or $23.35 per BOE, in the fourth quarter of 2012. The increase in the first quarter of 2013 compared to the first quarter of 2012 was primarily due to an increase of approximately $14.6 million in steam costs, due to a 47% increase in the average volume of steam injected and a 31% increase in the price of natural gas used in steam generation. Also contributing to the increase in steam costs was $3.2 million of emissions expense related to California greenhouse gas regulatory compliance in the first quarter of 2013. Also increasing over the same time period were well workover costs and contract services primarily related to Permian wells added in the last 12 months, well servicing and maintenance costs in the Uinta and contract labor in the Diatomite.

The increase in operating costs-oil and natural gas production in the first quarter of 2013 compared to the fourth quarter


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of 2012 was primarily due to an increase in steam costs primarily due to $3.2 million of emissions expense related to California greenhouse gas regulatory compliance. Also increasing over the same time period were well servicing and maintenance costs and transportation costs, partly related to refinery constraints in the Utah region during the fourth quarter of 2012. These increases were partially offset by a decrease in well workover costs in the Permian between periods.

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