BRY Berry Corporation

Berry Petroleum Company (NYSE:BRY) reported a net loss of $52.5 million, or $0.98 per diluted share, for the first quarter of 2011. Oil and gas revenues were $187 million during the quarter and discretionary cash flow totaled $85 million.

Net income for the quarter was impacted by a non-cash loss on hedges and other items. In total, for the first quarter of 2011, these items decreased net income by approximately $74.7 million, or $1.35 per diluted share for an adjusted first quarter net income of $22.2 million, or $0.41 per diluted share.

For the first quarter of 2011 and fourth quarter of 2010, average net production in BOE per day was as follows:

    First Quarter Ended   Fourth Quarter Ended March 31   December 31 2011 Production   2010 Production Oil (Bbls) 22,648   66 % 22,679   66 % Natural Gas (BOE) 11,757 34 % 11,805 34 % Total BOE per day 34,405 100 % 34,484 100 %  

Robert F. Heinemann, president and chief executive officer, said, “During the first quarter, Berry executed on its 2011 capital program drilling a total of 125 wells with two rigs in the diatomite and four rigs in the Permian. We began injecting steam into our new diatomite wells late during the first quarter and field-wide production has begun to respond in line with our expectations. We remain on track to reach 5,000 BOE/D by mid-year 2011. We have also entered into agreements to purchase approximately 6,000 additional net acres in the Wolfberry for approximately $123 million. This acquisition will increase our total inventory to approximately 470 wells on 40-acre spacing after this year. We now plan to run five rigs in the Permian for the balance of the year and expect our 2011 capital will increase to between $400 million and $450 million at current prices and expect our total average production for 2011 to be between 37,500 BOE/D and 39,500 BOE/D. Strong commodity prices and a narrow differential to WTI in California contributed to an excellent operating margin of $38 per BOE during the first quarter. Late in the first quarter, California crude oil began to trade at a premium to WTI and this premium is about $5 per barrel today. We should see the full impact of this premium in our operating margins during the second quarter.”

Operational Update

Michael Duginski, executive vice president and chief operating officer, stated, “Berry drilled approximately 75 wells on our diatomite property in the first quarter. In addition to injecting steam in these new wells, we have reestablished continuous operations and have increased steam injection throughout the field to over 40,000 BSPD. Production and reservoir temperatures are responding as expected. Current diatomite production is 3,000 BOE/D, up from an average of 2,250 BOE/D in the first quarter. We have submitted documentation to the California Division of Oil, Gas and Geothermal Resources and continue to expect approval of our development project in the second quarter. In the Permian, we drilled 14 wells during the quarter and results continue to be in line with our expectations. Production in the Permian increased by 35% during the quarter and averaged approximately 3,000 BOE/D.”

Financial Update

David Wolf, executive vice president and chief financial officer, stated, “We completed our credit facility borrowing base redetermination in April and raised our borrowing base from $875 million to $1.4 billion. While we did not increase lender commitments, the increased borrowing base gives us the flexibility to increase our liquidity by adding commitments as needed in the future. In addition to the increased borrowing base we reduced the pricing on our facility to be in line with the current market, extended the maturity by six months and added the flexibility to refinance our 2016 notes. Liquidity under our credit facility at the end of the first quarter was $633 million. Our per barrel results for the first quarter were generally in line with guidance with higher operating costs being impacted by a legal settlement accrual and increased workover activity during the quarter and our general and administrative expenses reflecting the impact of annual compensation awards.”

2011 Guidance

For 2011 the Company is issuing the following per BOE guidance:

    Anticipated   Three Months range in 2011 3/31/11 Operating costs-oil and gas production $ 16.50 - 18.50 $ 18.43 Production taxes 2.00 - 2.50 2.39 DD&A 16.00 - 18.00 16.83 G&A 3.75 - 4.25 5.26 Interest expense   5.25 – 6.25   5.06 Total $ 43.50 - 49.50 $ 47.97    

Explanation and Reconciliation of Non-GAAP Financial Measures

Discretionary Cash Flow ($ millions)

    Three Months Ended 3/31/11   12/31/10 Net cash provided by operating activities

$

100.4

$ 48.7 Add back: Net increase (decrease) in current assets 14.7 7.4 Add back: Net decrease (increase) in current liabilities including book overdraft (30.2 ) 17.7 Add back: Unwind of interest rate swaps   -     10.8 Discretionary cash flow $ 84.9 $ 84.6    

Reconciliation of First Quarter Net Income ($ millions)

    Three Months Ended 3/31/11 Adjusted net earnings $ 22.2 After tax adjustments: Non-cash hedge losses (74.6 ) Legal Settlement Accruals (0.7 ) Acquisition related items   0.6   Net loss, as reported $ (52.5 )    

Reconciliation of First Quarter Operating Margin Per BOE

    Three Months Ended 3/31/11 Average Sales Price $ 59.01 Operating costs 18.43 Production taxes   2.39 Operating Margin $ 38.19  

Teleconference Call

An earnings conference call will be held Thursday, April 28, 2011 at 10:00 a.m. Eastern Time (8:00 a.m. Mountain Time). Dial 800-260-8140 to participate, using passcode 33881600. International callers may dial 617-614-3672. For a digital replay available until April 28, 2011 dial 888-286-8010 passcode 79887394. Listen live or via replay on the web at www.bry.com.

About Berry Petroleum Company

Berry Petroleum Company is a publicly traded independent oil and gas production and exploitation company with operations in California, Colorado, Texas and Utah. The Company uses its web site as a channel of distribution of material company information. Financial and other material information regarding the Company is routinely posted on and accessible at http://www.bry.com/index.php?page=investor.

Safe harbor under the “Private Securities Litigation Reform Act of 1995”

Any statements in this news release that are not historical facts are forward-looking statements that involve risks and uncertainties. Words such as “estimate,” “expect,” “would,” “will,” “target,” “goal,” and forms of those words and others indicate forward-looking statements. These statements include but are not limited to forward-looking statements about acquisitions and the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this press release. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Important factors which could affect actual results are discussed in the Company’s filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

  CONDENSED INCOME STATEMENTS (In thousands, except per share data) (unaudited)   Three Months   3/31/11 12/31/10 Revenues Sales of oil and gas $ 187,389 $ 168,605 Sales of electricity 6,412 7,427 Gas marketing 3,685 3,968 Interest and other, net   128     980   Total   197,614     180,980   Expenses Operating costs – oil & gas 57,083 49,949 Operating costs – electricity 6,113 6,566 Production taxes 7,391 6,515 Depreciation, depletion & amortization - oil & gas 52,109 50,456 Depreciation, depletion & amortization - electricity 501 818 Gas marketing 3,516 3,687 General and administrative 16,291 14,457 Realized and unrealized loss on derivatives, net 127,516 62,330 Interest 15,655 17,168 Extinguishment of debt - 572 Bargain purchase gain (1,046 ) - Dry hole, abandonment, impairment & exploration   113     89   Total   285,242     212,607     Earnings (loss) before income taxes (87,628 ) (31,627 ) Income tax (benefit) provision   (35,131 )   (10,481 )   Net (loss) earnings $ (52,497 ) $ (21,146 )   Basic (loss) earnings per share $ (0.98 ) $ (0.40 )   Diluted (loss) earnings per share $ (0.98 ) $ (0.40 )   Cash dividends per share $ 0.075 $ 0.075     CONDENSED BALANCE SHEETS (In thousands) (unaudited)   3/31/11   12/31/10 Assets Current assets $ 189,258 $ 142,866 Property, buildings & equipment, net 2,725,567 2,655,792 Derivative instruments 1,562 2,054 Other assets   35,742   37,904 $ 2,952,129 $ 2,838,616 Liabilities & Shareholders’ Equity Current liabilities $ 339,357 $ 270,651 Deferred income taxes 322,990 329,207 Long-term debt 1,144,624 1,108,965 Derivative instruments 87,035 33,526 Other long-term liabilities 73,751 71,714 Shareholders’ equity   984,372   1,024,553 $ 2,952,129 $ 2,838,616     CONDENSED STATEMENTS OF CASH FLOWS (In thousands) (unaudited)   Three Months 3/31/11   12/31/10 Cash flows from operating activities: Net (loss) earnings $ (52,497 ) $ (21,146 ) Depreciation, depletion & amortization (DD&A) 52,610 51,274 Gain on purchase of oil and natural gas properties (1,047 ) - Extinguishment of debt - 572 Amortization of debt issuance costs and net discount 2,099 2098 Dry hole & impairment - 1 Unrealized loss on derivatives 124,459 51,609 Stock-based compensation 3,052 2,252 Deferred income taxes (44,321 ) (12,834 ) Other, net 680 (12 ) Cash paid for abandonment (103 ) (2 ) Change in book overdraft 4,736 (7,781 ) Net changes in operating assets and liabilities   10,766     (17,314 ) Net cash provided by operating activities 100,434 48,717   Cash flows from investing activities Capital Expenditures (130,672 ) (79,184 ) Property acquisitions (2,413 ) (179,892 ) Capitalized Interest   (10,392 )   (7,919 ) Net cash used in investing activities (143,477 ) (266,995 )   Net cash provided by financing activities   42,845     218,502     Net increase (decrease) in cash and cash equivalents (198 ) 224 Cash and cash equivalents at beg of year   278     54   Cash and cash equivalents at end of period $ 80   $ 278       COMPARATIVE OPERATING STATISTICS (unaudited)   Three Months     3/31/11 12/31/10 Change Oil and gas: Heavy Oil Production (Bbl/D) 16,226 16,548 Light Oil Production (Bbl/D)   6,422     6,131   Total Oil Production (Bbl/D) 22,648 22,679 Natural Gas Production (Mcf/D)   70,542     70,828   Total (BOE/D) 34,405 34,484   Per BOE: Average realized sales price $ 60.26 $ 53.55 13 % Average sales price including cash derivative settlements $ 59.01 $ 53.75 10 %   Oil, per Bbl: Average WTI price $ 94.60 $ 85.20 11 % Price sensitive royalties (3.57 ) (3.37 ) Gravity differential and other (5.68 ) (9.16 ) Crude oil derivatives non cash amortization   (7.06 )   (3.22 ) Oil revenue 78.29 69.45 13 % Add: Crude oil derivatives non cash amortization 7.06 3.22 Crude Oil derivative cash settlements   (10.24 )   (4.35 ) Average realized oil price $ 75.11 $ 68.32 10 %   Natural gas price: Average Henry Hub price per MMBtu $ 4.11 $ 3.80 8 % Conversion to Mcf 0.21 0.19 Natural gas derivatives non cash amortization (0.01 ) 0.05 Location, quality differentials and other   (0.09 )   (0.14 ) Natural gas revenue per Mcf 4.22 3.90 8 % Less: Natural gas derivatives non cash amortization 0.01 (0.05 ) Natural gas derivative cash settlements   0.41     0.50   Average realized natural gas price per Mcf 4.64 4.35 7 %   Operating costs $ 18.43 $ 15.73 17 % Production taxes   2.39     2.05   17 % Total operating costs 20.82 17.78 17 %   DD&A - oil and gas 16.83 15.89 6 % General & administrative expenses 5.26 4.55 16 %   Interest expense $ 5.06 $ 5.41 -6 %