BRY Berry Corporation

Berry Petroleum Company (NYSE:BRY) earned net income of $54 million, or $1.17 per diluted share, for the twelve months ended December 31, 2009. Total revenues were $575 million for 2009 and oil and gas revenues totaled $507 million. Discretionary cash flow totaled $256 million in 2009.

Robert F. Heinemann, president and chief executive officer, said, “While the fundamentals in 2009 were challenging, Berry had another excellent year of execution. With limited development capital of $135 million and acquisitions of $13.5 million, we were able to replace 200% of our 2009 production at an attractive FD&A metric of $8.30 per BOE. With this investment we were able to increase production by 2 percent over 2008, adjusted for divestitures. This performance demonstrates the strength of Berry’s asset portfolio which is supported by low base decline assets in California. Our 2009 capital program and acquisition activities focused on continuous investment in the diatomite and other California projects as well as new completion practices and consolidation of working interests in the Piceance. In the diatomite, we drilled 51 wells and increased production 68% over 2008 levels to average 3,100 BOE/D and averaged 3,650 BOE/D for the fourth quarter of 2009.

                                2009 Production 2008 Production Oil (Bbls) 19,688         66 % 20,330         64 % Natural Gas (BOE) 10,346   34 % 11,638   36 % Total BOE per day 30,034 100 % 31,968 100 % Less DJ basin production (divested 4/09) (765 ) (3,295 ) Total BOE per day – Continuing Operations 29,269 28,673  

Reserve Replacement of 200% with $149 million of Investment

Proved oil and gas reserves were estimated at 235 million BOE at December 31, 2009. This represents a 5% increase compared to 225 million BOE at year-end 2008, adjusted for divestitures. With capital investment of $135 million and acquisitions of $13.5 million, Berry replaced 200% of 2009 production at a cost of $8.30 per BOE. Including acquisitions, the Company added 21.5 million BOE. At year-end 2009, the Company’s proved reserve mix includes 130 million barrels of crude oil, condensate and natural gas liquids, and 632 billion cubic feet of natural gas, or 55% oil and 45% natural gas.

Geographically, 48% of proved reserves are in California, 35% are in the Rocky Mountain region and 17% in East Texas. Proved developed reserves represent 53% of total proved reserves. The year-end 2009 reserve estimates do not include the Company’s Permian acquisition which is expected to close in the first quarter of 2010 and will add approximately 11.2 million BOE, bringing the Company’s total proved reserves to 246 million BOE on a pro forma basis.

Fourth Quarter 2009 – Adjusted Net Income of $0.33 per share - Production of 29,150 BOE/D

For the fourth quarter ended December 31, 2009 the Company reported net income of $13.0 million, or $0.28 per diluted share. The fourth quarter net income includes items that affect operating results such as impairment charges related to reductions in drilling rig carrying values and other lease writedowns, a prior period adjustment related to royalties, sales of inventoried volumes at Poso Creek and a non-cash gain on derivatives. In total, for the fourth quarter of 2009, these items decreased net income by approximately $2.0 million, or $0.05 per diluted share, for an adjusted fourth quarter net income of $15.0 million, or $0.33 per diluted share. Discretionary cash flow during the fourth quarter was $61 million. Average production was 29,150 BOE/D in the fourth quarter of 2009, up 3% from 28,417 BOE/D in the third quarter of 2009. The diatomite asset continues to perform and production in the Piceance increased from 20 high volume completions performed during the last half of 2009. Operating costs increased from $14.99 per BOE during the third quarter to $16.89 per BOE during the fourth quarter, primarily due to higher steam costs in California due to increased spot natural gas prices which averaged approximately $4.28 per MMBtu in the fourth quarter of 2009 compared to $3.08 per MMBtu in the third quarter of 2009.

Business Outlook

Mr. Heinemann commented on Berry’s outlook, “In 2009 we acquired the McKittrick 21Z property in California and we believe this acquisition represents a next generation of heavy oil projects which can generate excellent margins in the current commodity price environment and we are actively seeking additional heavy oil opportunities.

“In January 2010, we entered into an agreement to acquire 11.2 million BOE of proved reserves in the Permian, establishing a new core area for Berry in the Permian basin. We expect this acquisition to close in the first quarter of 2010 and the assets are expected to produce approximately 1,300 BOE/D for the full year. We have hired an asset manager based in Midland, Texas, and are beginning to fill out our Permian asset team. We are focused on acquiring additional acreage and reserves in the Permian and during February 2010, we signed a purchase and sale agreement to acquire a 99% working interest in additional 3,200 gross acres in Midland County, Texas, for $14 million. This acquisition will add approximately 2 million BOE of proved reserves, based on internal estimates, from 22 producing wells and an additional 34 drilling locations on 40-acre spacing.”

Michael Duginski, executive vice president and chief operating officer, stated, “In 2010, we are focused on returning to growth and expect to increase production from 30,034 BOE/D in 2009 to a range of 32,250 BOE/D to 33,000 BOE/D in 2010. We will invest approximately 70% of our 2010 capital into oil projects to continue the development of the diatomite where we expect to increase our production to an exit rate of 5,000 BOE/D, begin the development of our recently acquired Permian assets and initiate three steam flood pilots in addition to our McKittrick 21Z property. As part of the development of our California assets, we expect to increase our net consumption of natural gas from approximately 30,000 MMBtu per day in 2009 to between 37,000 MMBtu and 41,000 MMBtu per day in 2010. As we develop our oil properties and our consumption of natural gas to generate steam increases, we will continue to develop our natural gas properties, running a one rig program in both the Piceance basin and East Texas. We completed the drilling of our first horizontal Haynesville well in January 2010 and expect to conclude completion activities during March 2010.”

David Wolf, executive vice president and chief financial officer, added, “Subsequent to our equity offering and Permian acquisition Berry will have approximately $650 million of liquidity and with a capital budget for 2010 ranging from $250 million to $290 million, Berry will fund its drilling activity from internally generated cash flow. Approximately 75% of our 2010 oil production is hedged and after accounting for our internal consumption of natural gas, 90% of our 2010 natural gas production is hedged, making our cash flow fairly insensitive to changes in commodity prices.”

2010 Guidance

For 2010 the Company is issuing the following guidance ranges based on $60 WTI and $5.00 HH:

          Amount per BOE Anticipated           range in 2010 2009 Operating costs-oil and gas production $ 17.00 – 20.00 $ 14.66 Production taxes 1.75 – 2.25 1.70 DD&A 12.00 – 14.00 13.10 G&A 4.00 – 4.50 4.61 Interest expense   4.00 – 5.00   4.67 Total $ 38.75 – 45.75 $ 38.74    

Explanation and Reconciliation of Non-GAAP Financial Measures

Discretionary Cash Flow

         

Three MonthsEnded

         

Twelve MonthsEnded

12/31/09 12/31/09 Net cash provided by operating activities $ 64.2 $ 212.6 Add back: Net increase (decrease) in current assets 0.2 10.1 Add back: Net decrease (increase) in current liabilities including book overdraft   (3.9 )   33.6 Discretionary cash flow $ 60.5 $ 256.3    

Reconciliation of Fourth Quarter Net Income

                   

Three MonthsEnded

12/31/09 Adjusted net income $ 15.0 After tax adjustments: Non-cash hedge gains 3.6 Poso Creek inventory trade sales 1.2 Drilling rig and lease impairments (4.1 ) Royalty adjustment   (2.7 ) Net income, as reported $ 13.0    

Finding, Development & Acquisition Cost Supporting Schedule

All expenditure amounts below are estimates (unaudited) (Amounts in millions):                   2009 Acquisition Costs $ 13.5 Capitalized Interest 30.1 Development Costs   134.9 Net Expenditures $ 178.5   Total reserves added, excluding production (MMBOE) 21.5   Estimated finding, development & acquisition cost per BOE $ 8.30    

Teleconference Call

An earnings conference call will be held Thursday, February 25, 2010 at 12:00 p.m. Eastern Time (10:00 a.m. Mountain Time). Dial 1-866-730-5763 to participate, using passcode 79554799. International callers may dial 857-350-1587. For a digital replay available until March 04, 2010 dial 1-888-286-8010 (passcode 53554269). 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 “expect”, "would," "will," "target," "goal," and forms of those words and others indicate forward-looking statements. Important factors which could affect actual results are discussed in PART 1, Item 1A. Risk Factors of Berry's 2009 Form 10-K filed with the Securities and Exchange Commission on February 25, 2010 under the heading "Other Factors Affecting the Company's Business and Financial Results" in the section titled "Management's Discussion and Analysis of Financial Condition and Results of Operations.”

  CONDENSED INCOME STATEMENTS (In thousands, except per share data) (unaudited)             Three Months Twelve Months 12/31/09     12/31/08 12/31/09     12/31/08 Revenues Sales of oil and gas $ 132,574 $ 134,670 $ 506,691 $ 649,248 Sales of electricity 10,033 12,302 36,065 63,525 Gas marketing 5,160 7,704 22,806 35,750 Gain (loss) on derivatives (51 ) (186 ) 6,514 (213 ) Gain (loss) on sale of assets (2 ) (1,807 ) 826 (1,297 ) Interest and other, net   435     995     1,810     3,504   Total   148,149     153,678     574,712     750,517   Expenses Operating costs – oil & gas 45,295 44,600 156,612 188,758 Operating costs – electricity 9,329 9,271 31,400 54,891 Production taxes 3,733 6,213 18,144 26,876 Depreciation, depletion & amortization - oil & gas 35,648 38,133 139,919 125,595 Depreciation, depletion & amortization - electricity 743 821 3,681 2,812 Gas Marketing 5,082 5,985 21,231 32,072 General and administrative 12,094 17,967 49,237 54,279 Interest 14,722 9,032 49,923 23,942 Extinguishment of debt - - 10,823 - Dry hole, abandonment, impairment & exploration 5,216 3,147 5,425 10,543 Bad debt expense   -     38,665     -     38,665   Total   131,862     173,834     486,395     558,433     Income (loss) before income taxes 16,287 (20,156 ) 88,317 192,084 Income tax provision (benefit)   3,668     (9,069 )   28,349     70,308   Income (loss) from continuing operations 12,619 (11,087 ) 59,968 121,776 Income (loss) from discontinued operations, net of tax 385 (904 ) (5,938 ) 11,753   Net income (loss) $ 13,004   $ (11,991 ) $ 54,030   $ 133,529     Basic net income (loss) from continuing operations per share $ 0.27 $ (0.24 ) $ 1.31 $ 2.70 Basic net income (loss) from discontinued operations per share   0.01     (0.02 )   (0.13 )   0.26   Basic net income (loss) per share $ 0.28   $ (0.26 ) $ 1.18   $ 2.96     Diluted net income (loss) from continuing operations per share $ 0.27 $ (0.24 ) $ 1.30 $ 2.66 Diluted net income (loss) from discontinued operations per share   0.01     (0.02 )   (0.13 )   0.26   Diluted net income (loss) per share $ 0.28   $ (0.26 ) $ 1.17   $ 2.92     Cash dividends per share $ 0.075 $ 0.075 $ 0.30 $ 0.30   Weighted average common shares: Basic   44,679     44,543     44,625     44,485   Diluted   45,042     44,729     44,846     45,063         CONDENSED BALANCE SHEETS (In thousands) (unaudited)             12/31/09           12/31/08 Assets Current assets $ 103,476 $ 189,080 Property, buildings & equipment, net 2,106,385 2,254,425 Fair value of derivatives 735 79,696 Other assets   29,539   19,182 $ 2,240,135 $ 2,542,383 Liabilities & Shareholders’ Equity Current liabilities $ 152,137 $ 260,625 Deferred taxes 237,161 270,323 Long-term debt 1,008,544 1,131,800 Other long-term liabilities 63,198 47,888 Fair value of derivatives 75,836 4,203 Shareholders’ equity   703,259   827,544 $ 2,240,135 $ 2,542,383       CONDENSED STATEMENTS OF CASH FLOWS (In thousands) (unaudited)             Twelve Months 12/31/09           12/31/08 Cash flows from operating activities: Net income $ 54,030 $ 133,529 Depreciation, depletion & amortization (DD&A) 145,788 141,049 Dry hole & impairment 14,859 9,932 Deferred income taxes 19,998 67,982 Commodity derivatives 247 (108 ) Stock based compensation 8,626 9,313 Loss on sale of asset 79 1,297 Cash paid for abandonment (1,030 ) (4,607 ) Other, net 13,634 (756 ) Change in book overdraft (16,018 ) 23,984 Allowance for bad debt - 38,511 Net changes in operating assets and liabilities   (27,637 )   (10,557 )   Net cash provided by operating activities 212,576 409,569   Net cash used in investing activities (38,754 ) (1,086,769 ) Net cash provided by financing activities   (168,751 )   677,124     Net increase (decrease) in cash and cash equivalents 5,071 (76 )   Cash and cash equivalents at beginning of year   240     316     Cash and cash equivalents at end of period $ 5,311   $ 240       COMPARATIVE OPERATING STATISTICS (unaudited)         Three Months       Twelve Months 12/31/09     12/31/08     Change 12/31/09     12/31/08     Change Oil and gas: Heavy Oil Production (Bbl/D) 17,280 15,999 16,842 16,633 Light Oil Production (Bbl/D) 2,719 3,659 2,846 3,697 Total Oil Production (Bbl/D) 19,999 19,658 19,688 20,330 Natural Gas Production (Mcf/D)   54,899     95,548     62,074     69,834   Net production-BOE per day 29,149 35,583 -18 % 30,034 31,968 -6 % Per BOE: Average sales price before hedges $ 50.76 $ 40.61 25 % $ 41.23 $ 73.64 -44 % Average sales price after hedges $ 47.08 $ 45.56 3 % $ 46.59 $ 62.03 -25 %   Oil, per Bbl: Average WTI price $ 76.13 $ 59.08 29 % $ 62.09 $ 99.75 -38 % Price sensitive royalties (2.64 ) (1.69 ) (2.04 ) (2.95 ) Gravity differential and other (9.63 ) (8.55 ) (9.08 ) (11.32 ) Crude oil hedges (6.12 ) 4.69 6.55 (16.89 ) Correction to royalties payable   (1.78 )   -     (0.24 )   1.42   Average oil sales price after hedging 55.96 53.53 5 % $ 57.28 $ 70.01 -18 %   Natural gas price: Average Henry Hub price per MMBtu 4.17 6.95 -40 % $ 4.00 $ 9.04 -56 % Conversion to Mcf 0.21 0.35 0.20 0.46 Natural gas hedges 0.29 0.89 0.49 0.20 Location, quality differentials, other   (0.12 )   (2.67 )   (0.60 )   (2.59 ) Avg. gas sales price after hedging 4.55 5.52 -18 % 4.09 7.11 -42 %   Operating costs $ 16.89 $ 15.07 12 % $ 14.66 $ 17.99 -19 % Production taxes   1.39     2.10   -34 %   1.70     2.56   -34 % Total operating costs 18.28 17.17 6 % 16.36 20.55 -19 %   DD&A - oil and gas 13.29 12.89 3 % 13.10 11.97 9 % General & administrative expenses 4.51 6.07 -26 % 4.61 5.17 -11 %   Interest expense $ 5.49 $ 3.05 80 % $ 4.67 $ 2.28 105 %