Berry Petroleum Reports 2010 Results

Berry Petroleum Company (NYSE:BRY) generated net earnings of $83 million, or $1.52 per diluted share, for the twelve months ended December 31, 2010. Oil and gas revenues totaled $620 million and discretionary cash flow totaled $391 million in 2010.

Robert F. Heinemann, president and chief executive officer, said, “Berry returned to growth in 2010, increasing oil and natural gas production from continuing operations by 12% over 2009 levels and maintaining a two-thirds crude oil to natural gas mix. Berry’s production growth in 2010 was supported by our entry in the Permian basin, where we acquired a total of 20,000 net acres in the Wolfberry trend. In addition to providing us with a five-year drilling inventory, the Permian acquisitions allowed us to reallocate capital during 2010 into primary oil production as we awaited permits to develop our California diatomite oil asset.”

2010 Production2009 Production
Oil (Bbls) 21,713 66 % 19,688 66 %
Natural Gas (BOE) 10,95334%10,34634%
Total BOE per day 32,666 100 % 30,034 100 %
Less DJ basin production (divested 4/09) - (765 )
Total BOE per day – Continuing Operations 32,666 29,269

Added 47.8 MMBOE and Replaced 400% of 2010 Production

Proved oil and gas reserves were estimated at 271 million BOE at December 31, 2010. This represents a 15% increase compared to 235 million BOE at year-end 2009. The Company added 47.8 million BOE to proved reserves from a development capital investment of $310 million and acquisition costs of $334 million. Finding, Development and Acquisition (FD&A) costs were $14.08 per BOE. At year-end 2010, the Company’s proved reserve mix includes 166 million barrels of crude oil, condensate and natural gas liquids, and 630 billion cubic feet of natural gas, or 61% oil and 39% natural gas.

Berry’s oil reserves grew 28% during 2010, supported by the performance of its assets in three oil basins. These basins make up 64% of proved reserves with 43% in California, 12% in the Permian basin and 9% in the Uinta. Proved developed reserves represent 49% of total proved reserves.

Fourth Quarter 2010 – Adjusted Earnings of $0.35 per share, Production of 34,484 BOE/D and Discretionary Cash Flow of $85 million

For the fourth quarter ended December 31, 2010 the Company reported a net loss of $(21.1) million, or $(0.40) per diluted share. The fourth quarter earnings included a non-cash commodity hedge charge that decreased earnings by approximately $39.8 million or $0.74 per diluted share. Without this impact, fourth quarter earnings would have been $18.7 million or $0.35 per diluted share. Discretionary cash flow during the fourth quarter was $85 million with an operating margin of $36 per BOE. Average production was 34,484 BOE/D in the fourth quarter of 2010, up 2% from 33,867 BOE/D in the third quarter of 2010. Production in the Permian basin increased 66% from 1,340 BOE/D in the third quarter to 2,220 BOE/D in the fourth quarter as we executed our development plan and closed on our October 2010 acquisition. In the diatomite, production remained relatively flat at 2,320 BOE/D. While drilling and full steam injection resumed in the fourth quarter, the reservoir has not yet been reheated to optimal production temperatures. Additionally, a portion of the existing producing area was depressurized during the quarter to allow for new wells to be drilled.

Business Outlook

Mr. Heinemann commented on Berry’s outlook, “In 2010 we executed on our oil strategy to bring additional opportunities in the portfolio that will allow us to grow our oil production, operating margins and cash flow per share. Our entry into the Permian basin through three separate privately negotiated transactions provided us with a total of 400 drilling locations on 40-acre spacing and an additional 400 locations on 20-acre spacing. In California, we determined our McKittrick 21Z oil pilot project was economic and plan to begin the development of that asset in 2011. Additionally we have been pleased with the performance of our Ethel D oil pilot and will begin commercial development during 2011. In the Uinta, we drilled 20 wells in the Ashley Forest and 4 wells in Lake Canyon during 2010 and were pleased with the results. Given our outlook at both the Ashley Forest and Lake Canyon, we are excited about the future growth potential in the Uinta.

“Our 2011 development program which focuses on our three oil basins should allow us to grow our oil production by 20%, increase operating margins and grow our cash flow per share. We plan to continue adding acreage in the Permian and expand our position in California through additional lease arrangements with major oil companies. At a WTI price of $90 per barrel, margins from our Wolfberry assets exceed $60 per BOE. At year-end 2010, the differential for California crude oil was approximately $6 per barrel and our California margins also exceeded $60 per BOE. Today, however, our California crude oil is selling at a premium to the benchmark WTI index and our margins in California are in excess of $70 per BOE.”

Michael Duginski, executive vice president and chief operating officer, stated, “In 2011, we expect to increase our total production from 32,666 BOE/D in 2010 to a range of 37,000 BOE/D to 39,000 BOE/D in 2011. We will invest approximately 90% of our 2011 capital into our oil projects. In the Permian we are budgeting $120 million to run four rigs and drill approximately 75 wells and expect to average 5,200 BOE/D in 2011. In the diatomite asset, full project regulatory approval remains on schedule and we plan to run two rigs and invest approximately $110 million and expect to increase our production to 5,000 BOE/D by mid-year. At McKittrick 21Z, we plan to drill 45 wells and begin to inject steam and heat the reservoir. At Ethel D, we plan to expand the commercial steam flood development and drill 25 wells on the property during 2011.”

David Wolf, executive vice president and chief financial officer, added, “We expect our capital expenditures in 2011 will range between $375 million and $425 million and should be funded from operating cash flow. Approximately 70% of our 2011 oil production is hedged and after accounting for our internal consumption of natural gas, approximately 90% of our 2011 natural gas production is hedged. We issued $300 million of 10-year 6.75% senior notes during the fourth quarter and refinanced our credit facility with a new $875 million 5-year facility providing us with liquidity of approximately $700 million. Our strong financial position should allow us to meet our organic growth objectives and acquisition targets while maintaining our focus on growing cash flow per share.”

Accounting Matters

As a result of discussions with the Securities and Exchange Commission, the Company will file its 2010 Form 10-K and restate the presentation of certain of the Company’s hedging activities from continuing operations to the discontinued operations of the Company’s DJ basin assets for the years 2006 through 2009. The net result of these changes is to decrease net earnings from continuing operations by $1 million, $7 million, $1 million, and $13 million for the years ended December 31, 2006, 2007, 2008 and 2009, respectively, and increase net earnings from discontinued operations by the same amounts. These changes will not result in any changes to the Company’s cash flow or to total net earnings.

2011 Guidance

For 2011 the Company is issuing the following per BOE guidance ranges based on $75 WTI and $4.50 HH:

Anticipated Three Months Twelve Months
range in 2011 12/31/2010 12/31/2010
Operating costs-oil and gas production $ 16.50 - 18.50 $ 15.74 $ 15.95
Production taxes 2.00 - 2.50 2.05 1.93
DD&A 16.00 - 18.00 15.90 15.05
G&A 3.75 - 4.25 4.56 4.43
Interest expense 5.25 – 6.25 5.41 5.58
Total $ 43.50 - 49.50 $ 43.66 $ 42.94

Explanation and Reconciliation of Non-GAAP Financial Measures

Discretionary Cash Flow

Three Months
Ended

Twelve Months
Ended

12/31/10 12/31/10
Net cash provided by operating activities $ 48.7 $ 367.2
Add back: Net increase (decrease) in current assets 7.4 (12.5 )
Add back: Net decrease (increase) in current liabilities including book overdraft 17.7 (12.7 )
Add back: Unwind of interest rate swaps 10.8 10.8
Add back: Recovery of Flying J bad debt - 38.5
Discretionary cash flow $ 84.6 $ 391.3

Reconciliation of Fourth Quarter Net Earnings

Three Months
Ended

12/31/10
Adjusted net earnings $ 18.7
After tax adjustments:
Non-cash hedge loss and other (39.8 )
Net earnings, as reported $ (21.1 )

Reconciliation of Fourth Quarter Operating Margin Per BOE

Three Months
Ended

12/31/10
Average Sales Price $ 53.75
Operating costs 15.74
Production taxes 2.05
Operating Margin $ 35.96

Finding, Development & Acquisition Cost Supporting Schedule

All expenditure amounts below are estimates (unaudited)
(Amounts in millions):
2010
Acquisition Costs $ 334.4
Capitalized Interest 28.3
Development Costs 310.1
Net Expenditures $ 672.8
Total reserves added, excluding production (MMBOE) 47.8
Estimated finding, development & acquisition cost per BOE $ 14.08

Teleconference Call

An earnings conference call will be held Tuesday, March 1, 2011 at 12:00 p.m. Eastern Time (10:00 a.m. Mountain Time). Dial 800-299-9630 to participate, using passcode 31993783. International callers may dial 617-786-2904. For a digital replay available until March 8, 2011 dial 888-286-8010, passcode 13985090. 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 MonthsTwelve Months
Restated
12/31/1009/30/1012/31/1012/31/09
Revenues
Sales of oil and gas $168,605 $ 151,671 $619,608 $ 500,532
Sales of electricity 7,427 9,451 34,740 36,065
Gas marketing 3,968 4,918 22,162 22,806
Realized and unrealized gain (loss) on derivatives (62,330) (27,178 ) (31,847) (7,756 )
Settlement of Flying J bankruptcy claim - - 21,992 -
Gain (loss) on sale of assets - - - 826
Interest and other, net 9803623,3001,810
Total 118,650139,224669,955554,283
Expenses
Operating costs – oil & gas 49,949 46,782 190,218 156,612
Operating costs – electricity 6,566 7,220 31,295 31,400
Production taxes 6,515 6,215 22,999 18,144
Depreciation, depletion & amortization - oil & gas 50,456 49,367 179,432 139,919
Depreciation, depletion & amortization - electricity 818 819 3,225 3,681
Gas marketing 3,687 4,067 19,896 21,231
General and administrative 14,457 12,399 52,846 49,237
Interest 17,168 15,586 66,541 49,923
Extinguishment of debt 572 - 573 10,823
Transaction costs on acquisitions, net of gain -2,635 -
Dry hole, abandonment, impairment & exploration 89 586 2,311 5,425
Bad debt expense (recovery) --(38,508)-
Total 150,277143,041533,463486,395
Earnings before income taxes (31,627) (3,817 ) 136,492 67,888
Income tax provision (benefit) (10,481)(794)53,96820,664
Earnings from continuing operations (21,146) (3,023 ) 82,524 47,224
Earnings from discontinued operations, net of tax - - - 6,806
Net earnings $(21,146)$(3,023)$82,524$54,030
Basic earnings from continuing operations per share $(0.40) $ (0.06 ) $1.54 $ 1.03
Basic earnings from discontinued operations per share ---0.15
Basic earnings per share $(0.40)$(0.06)$1.54$1.18
Diluted earnings from continuing operations per share $(0.40) $ (0.06 ) $1.52 $ 1.02
Diluted earnings from discontinued operations per share ---0.15
Diluted earnings per share $(0.40)$(0.06)$1.52$1.17
Cash dividends per share $0.075 $ 0.075 $0.30 $ 0.30
CONDENSED BALANCE SHEETS
(In thousands)
(unaudited)
12/31/1012/31/09
Assets
Current assets $142,866 $ 103,476
Property, buildings & equipment, net 2,655,792 2,106,385
Fair value of derivatives 2,054 735
Other assets 37,90429,539
$2,838,616$2,240,135
Liabilities & Shareholders’ Equity
Current liabilities $270,651 $ 152,137
Deferred taxes 329,207 237,161
Long-term debt 1,108,965 1,008,544
Other long-term liabilities 71,714 63,198
Fair value of derivatives 33,526 75,836
Shareholders’ equity 1,024,553703,259
$2,838,616$2,240,135
CONDENSED STATEMENTS OF CASH FLOWS
(In thousands)
(unaudited)
Three MonthsTwelve Months
12/31/1009/30/1012/31/1012/31/09
Cash flows from operating activities:
Net earnings $(21,146) $ (3,023 ) $82,524 $ 54,030
Depreciation, depletion & amortization (DD&A) 51,274 50,186 182,657 145,788
Extinguishment of debt 572 - 573 10,823
Amortization of debt issuance costs and net discount 2098 2,164 8,481 6,827
Dry hole & impairment 1 49 1,478 14,859
Derivatives 51,609 37,110 42,609 247
Stock based compensation 2,252 2,126 9,386 8,626
Deferred income taxes (12,834) 6,391 54,698 19,998
Loss on sale of asset - - - 79
Other, net (12) - (12) (4,016 )
Cash paid for abandonment (2) (295 ) (1,832) (1,030 )
Allowance for bad debt - - (38,508) -
Change in book overdraft (7,781) 6,303 528 (16,018 )
Net changes in operating assets and liabilities (17,314)82,64024,655(27,637)
Net cash provided by operating activities 48,717 183,651 367,237 212,576
Cash flows from investing activities
Capital Expenditures (79,184) (95,917 ) (310,139) (134,946 )
Acquisitions (179,892) (3,843 ) (334,409) (13,497 )
Capitalized Interest (7,919) (7,348 ) (28,321) (30,107 )
Proceeds from sale of assets ---139,796
Net cash used in investing activities (266,995) (107,108 ) (672,869) (38,754 )
Net cash provided by financing activities 218,502(76,728)300,599(168,751)
Net increase (decrease) in cash and cash equivalents 224 (185 ) (5,033) 5,071
Cash and cash equivalents at beg of year 542395,311240
Cash and cash equivalents at end of period $278$54$278$5,311
COMPARATIVE OPERATING STATISTICS
(unaudited)
Three MonthsTwelve Months
Restated
12/31/1009/30/10Change12/31/1012/31/09Change
Oil and gas:
Heavy Oil Production (Bbl/D) 16,54816,72217,124 16,842
Light Oil Production (Bbl/D) 6,1315,0494,5892,846
Total Oil Production (Bbl/D) 22,67921,77121,713 19,688
Natural Gas Production (Mcf/D) 70,82872,57665,72062,074
Total BOE per day 34,48433,86732,666 30,034
Less DJ basin production (divested 4/09) ---765
Total BOE per day – Continuing Operations 34,48433,8672%32,666 29,269 12%
Per BOE:
Average realized sales price $53.55$48.7310%$52.14 $ 46.72 12%
Average sales price including cash derivative $53.75$51.884%$53.84 $ 46.02 17%
Oil, per Bbl:
Average WTI price $85.20$76.2012%$79.59 $ 62.09 28%
Price sensitive royalties (3.37)(2.91)(3.06) (2.04 )
Gravity differential and other (9.16)(8.87)(8.92) (9.08 )
Crude oil derivatives non cash amortization (3.22)(2.89)(2.59) -
Crude oil derivatives cash settlements - - - 7.47
Correction to royalties payable ---(0.24)
Oil revenue 69.45 61.53 13%65.02 58.20 12%
Add: Crude oil derivatives non cash amortization 3.22 2.89 2.59 -
Crude Oil derivative cash settlements (4.35)1.14(0.90)(0.92)
Average realized oil price $68.32 $ 65.56 4%$66.71 $ 57.28 16%
Natural gas price:
Average Henry Hub price per MMBtu $3.80 $ 4.38 -13%$4.39 $ 4.00 10%
Conversion to Mcf 0.19 0.22 0.22 0.20
Natural gas derivatives non cash amortization 0.05 0.09 0.08 0.23
Natural gas derivative cash settlements --- -
Location, quality differentials, other (0.14)(0.40)(0.24)(0.59)
Natural gas revenue per Mcf 3.90 4.29 -9%4.45 3.84 16%
Less: Natural gas derivatives non cash amortization (0.05) (0.09 ) (0.08) -
Natural gas derivative cash settlements 0.500.350.37(0.04)
Average realized natural gas price per Mcf 4.35 4.55 -4%4.74 3.80 25%
Operating costs $15.74 $ 15.01 5%$15.95 $ 14.66 9%
Production taxes 2.052.003%1.931.7014%
Total operating costs 17.79 17.01 5%17.88 16.36 9%
DD&A - oil and gas 15.90 15.84 1%15.05 13.10 14%
General & administrative expenses 4.56 3.98 16%4.43 4.61 -4%
Interest expense $5.41 $ 5.00 8%$5.58 $ 4.67 19%

Contacts:

Berry Petroleum Company
Investors and Media
David Wolf, 1-303-999-4400
Shawn Canaday, 1-866-472-8279
www.bry.com
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