February 23, 2012 at 07:05 AM EST
Berry Petroleum Reports 2011 Results

Berry Petroleum Company (NYSE:BRY) reported a net loss of $228 million, or $4.21 per diluted share in 2011. Oil and gas revenues were $871 million and discretionary cash flow totaled $462 million with cash provided by operating activities of $456 million.

Net earnings for 2011 were affected by a net non-cash impairment of the Company's natural gas properties in E. Texas, a net non-cash gain on derivative instruments, and other items. In total, these items decreased net earnings by $377 million. Adjusted net earnings were $149 million, or $2.69 per diluted share.

Production for the full year 2011 was 35,687 BOE/D. Oil production increased 14% in 2011 to 24,771 BOE/D and the Company's oil mix increased from 66% of production in 2010 to 70% of production in 2011. Total production volumes were up 9% from 32,666 BOE/D in 2010. Development capital for 2011 was $527 million.

For 2011 and 2010, Berry's average net production in BOE per day was as follows:

2011 Production2010 Production
Oil (Bbls) 24,771 70 % 21,713 66 %
Natural Gas (BOE) 10,916 30 % 10,953 34 %
Total BOE per day 35,687 100 % 32,666 100 %

Total Proved Reserves of 275 MMBOE; Pre-Tax PV10 of $5.7 Billion, 95% of value from Berry's three oil basins

Proved oil and gas reserves were estimated at 275 million BOE at December 31, 2011. Proved oil reserves were up a total of 12% to 186 million barrels with oil reserves increasing to 68% of total reserves. Reserve growth was driven by activity in Berry's three oil basins where the Company invested $527 million of development capital and made $158 million of oil acquisitions during 2011. These basins make up 73% of proved reserves with 44% in California, 21% in the Permian basin and 8% in the Uinta. Natural gas reserves were down 15%, or 16 million BOE, to 89 million BOE. The year-end reserve estimate includes 20 MMBOE of natural gas reserves in E. Texas that were reclassified from proved to probable due to current low natural gas prices and the assumption that these reserves will not be developed within five years of the date they were originally recorded as proved. Excluding this revision, the company added a total of 36 million BOE of proved reserves after production of 13 million BOE, replacing approximately 275% of 2011 production. At year-end 2011, the Company's proved reserve mix includes 186 million barrels of oil, condensate and natural gas liquids, and 534 billion cubic feet of natural gas, or 68% oil and 32% natural gas. Proved developed reserves increased to 53% of total reserves from 49% in 2010. Berry's pre-tax PV10 increased to $5.7 billion, a 50% increase from the year-end 2010 value of $3.8 billion, with 95% of the value coming from Berry's oil assets. The Company's after tax PV10 at year-end 2011 was $4.0 billion compared to $2.8 billion at year-end 2010.

Robert Heinemann, president and chief executive officer said, “Berry delivered another year of double digit oil growth in 2011. Investing our 2011 capital in our three oil basins provided oil growth of 14% during the year. While we were impacted by regulatory delays that slowed the pace of development in the diatomite, our portfolio of high return oil assets allowed us to accelerate the growth of our next generation steam floods and Permian assets and begin to appraise our large resource base in the Uinta. Our operating margin grew to $45 per BOE in 2011 from $36 per BOE in 2010 driven by oil production which increased from 66% of production in 2010 to 70% of production in 2011. Our investment in 2011 also delivered solid oil reserve growth. Proved oil reserves increased 29 million BOE in 2011 after oil production of 9 million BOE and our pre-tax PV10 increased 50% over the same period."

Fourth Quarter 2011 - Adjusted Earnings of $0.76 per share, Production of 35,790 BOE/D and Discretionary Cash Flow of $134 million

For the fourth quarter of 2011 the Company reported a net loss of $415 million, or $7.62 per diluted share. The fourth quarter earnings included a non-cash impairment of the Company's E. Texas natural gas assets, a non-cash loss on derivative instruments, and other items that decreased earnings by $457 million. Adjusted net earnings were $42 million or $0.76 per diluted share. Discretionary cash flow during the fourth quarter was $134 million with an operating margin of $48 per BOE.

For the fourth and third quarters of 2011, Berry's average net production in BOE per day was as follows:

Fourth Quarter 2011

Third Quarter 2011

Oil (Bbls) 25,663 72 % 26,091 71 %
Natural Gas (BOE) 10,127 28 % 10,825 29 %
Total BOE per day 35,790 100 % 36,916 100 %

Production in the fourth quarter of 2011 was 35,790 BOE/D, down 3% from the third quarter of 2011. As expected, diatomite production decreased 820 BOE/D during the fourth quarter to 3,000 BOE/D, as a portion of the Company's active wells were off line pending required well testing and regulatory approvals. While Permian production increased from 5,200 BOE/D in the third quarter to 5,600 BOE/D in the fourth quarter, fourth quarter production was impacted by gas plant curtailments which reduced production by approximately 800 BOE/D. Production in the Uinta basin was flat during the quarter at approximately 5,500 BOE/D.

2012 Outlook

Mr. Heinemann commented on Berry's outlook: “In 2012, we will continue to focus on growing oil production in California, the Permian and Utah which should drive improved margins and cash flow. We plan to invest between $600 - $650 million and grow total production to between 38,000 BOE/D and 39,000 BOE/D. While the mid-point of our guidance reflects eight percent total production growth over 2011, our oil production is expected to grow by nearly 20% in 2012 and our production stream should increase to over 75% oil for the year. We expect our natural gas assets will decline approximately 20% during the year. Growth in our oil assets should allow us to continue growing our margin to approximately $50 per BOE in 2012 at current prices.

In California, our 2012 plans will focus on returning to growth in the diatomite and aggressively developing our next generation steam floods. In the Permian we will focus on our Wolfberry vertical program and appraising our acreage position. We will continue to appraise our large acreage position in the Uinta focusing on the oil weighted Uteland Butte and Wasatch developments.”

Operations Update

Michael Duginski, executive vice president and chief operating officer, stated, “In the Permian, we drilled 14 wells during the fourth quarter of 2011. Permian production increased 8% from 5,200 BOE/D in the third quarter to 5,600 BOE/D in the fourth quarter. While Permian production grew during the quarter, production was impacted by gas plant curtailments which reduced the quarter's production by approximately 800 BOE/D. We are working to address potential gas plant curtailment in the Permian. However, we do expect that curtailments will impact our Permian production periodically throughout 2012 as gas plants expand and infrastructure in the basin is upgraded to meet current demand. In 2012, we plan to invest $250 million to operate a five rig drilling program and drill approximately 100 gross operated wells. In addition to our traditional Wolfberry vertical program we will drill approximately four appraisal wells on our newly acquired prospective acreage.”

“In Utah, we have completed three operated Uteland Butte horizontal wells. We were not able to achieve a full completion on one of these three wells. While we do not have 30 days of production from the two remaining wells, we expect our 30-day average initial production rates on these two wells will be approximately 300 BOE/D with approximately 90% of the production stream being oil. The 24-hour peak production rate for these two wells was in the 600 BOE/D - 675 BOE/D range. We are in the early stages of the development in this play and estimate that we could have between 800 and 1,400 locations in our development of the Uteland Butte and Wasatch. Results from our vertical Wasatch test wells have also been positive with average initial production rates in the 100 BOE/D range and with oil making up approximately 90% of the production stream on average. In the Uinta, we plan to run a three rig program and invest approximately $130 million to drill approximately 85 wells focused on developing areas of higher oil potential in the Green River, Uteland Butte and Wasatch formations.”

“In the diatomite, average production decreased during the quarter to 3,000 BOE/D. During 2011, Berry was impacted by new operating requirements which were part of the regulatory approval process for diatomite development. Implementation of these operating requirements negatively impacted the pace of drilling and steam injection. In our third quarter 2011 earnings call, we described a set of activities which included improved field surveillance and the redesign of our steam injection process which we expected to require six to nine months to complete. These changes to our surveillance and design processes remain on track to be completed in the second quarter of 2012. We are also working constructively with DOGGR to return wells to production and enable an increase in the pace of our development in 2012. We expect to drill approximately 70 wells during the year and invest approximately $85 million including the installation of surface facilities and equipment. We plan to bring these wells online during the summer. Diatomite production should remain flat during the first quarter of 2012 and begin to grow in the back half of 2012 as we complete our development program and bring wells online.”

"Outside the diatomite, we plan to invest $120 million in California to maintain our high margin assets in S. Midway-Sunset and grow production from our new steam floods including McKittrick 21Z. At McKittrick, we drilled 44 wells during 2011 and these wells should begin to contribute to production during the first quarter of 2012. We plan to drill approximately 50 additional wells in 2012. We also plan to drill 35 wells in our other steam flood projects at Fairfield, Pan and Main Camp during the year."

Financial Update

David Wolf, executive vice president and chief financial officer, stated, “Berry's financial position remains strong. We expect that we will be able to generate approximately $600 million of cash flow in 2012 at current prices which would fund our planned development capital expenditures. The sizable additions to our oil reserves at year-end 2011 should also allow us to maintain a strong liquidity position which was approximately $650 million at year-end.”

2012 Guidance

For 2012 the Company is issuing the following per BOE guidance:

Anticipated rangeThree MonthsTwelve Months
in 201212/31/201112/31/2011
Operating costs — oil and gas production $ 17.00 - 19.50 $ 18.11 $ 18.23
Production taxes 2.50 - 3.25 2.64 2.58
DD&A — oil and gas production 15.00 - 18.00 16.77 16.42
General and administrative 4.25 - 5.50 4.44 4.74
Interest expense 5.50 - 6.25 5.93 5.59
Total $ 44.25 - 52.50 $ 47.89 $ 47.56

Reserve Quantities:

2011
OilGas
MBblMMcfMBOE
Proved developed and undeveloped reserves:
Beginning of year 166,181 630,192 271,213
Revision of previous estimates (4,054 ) (146,349 ) (28,446 )
Extensions and discoveries 19,601 65,992 30,600
Production (9,041 ) (23,907 ) (13,025 )
Purchase of reserves in place 13,193 8,351 14,584
End of year 185,880 534,279 274,926
Proved developed reserves:
Beginning of year 88,917 268,566 133,678
End of year 107,849 221,606 144,783
Reserve Quantities by Property (MMBOE):
ProvedProved
ProvedDevelopedUndeveloped

Name, State

ReservesReservesReserves
S. Midway, CA 58.0 50.9 7.1
N. Midway, CA 62.4 34.0 28.4
Permian, TX 56.9 16.5 40.4
Uinta, UT 23.2 13.3 9.9
Piceance, CO 55.0 11.9 43.1
E. Texas 19.4 18.2 1.2
Totals 274.9 144.8 130.1

Non-GAAP Financial Measures

This press release includes discussion of “discretionary cash flow,” “adjusted net earnings,” “operating margin per BOE,” and “Pre-tax PV10,” each of which are “non-GAAP financial measures” as defined in Regulation G of the Securities Exchange Act of 1934, as amended. Discretionary cash flow consists of cash provided by operating activities before changes in working capital items, certain payments related to unwinding interest rate swaps, and recovery of bad debt. The Company believes that discretionary cash flow provides additional information to investors about the Company's ability to meet future requirements for debt service, capital expenditures and working capital. Adjusted net earnings consists of net earnings before non-cash derivatives gains (losses), oil and gas property impairments and charges related to the extinguishment of debt. The Company believes that adjusted net earnings is useful for evaluating the Company's operational performance from oil and natural gas properties. Operating margin per BOE consists of oil and natural gas revenues less oil and natural gas operating expenses and production taxes divided by the total BOE sold during the period. The Company uses operating margin per barrel as a measure of profitability and believes it provides useful information to investors because it relates the Company's oil and natural gas revenue and oil and natural gas operating expenses to its total units of production providing a gross margin per unit of production. Using this measure, investors can evaluate how profitability varies on a per unit basis each period. Pre-tax PV10 is defined as standardized measure before the present value of the Company's future net revenues before income taxes discounted at 10%. The Company believes that pre-tax PV10 is helpful to investors because it is a widely used industry standard and is helpful when comparing the Company's asset base and performance to other comparable oil and natural gas exploration and production companies. These measures should not be considered in isolation or as a substitute for cash flows from operating activities, net income, operating income or any other measure of financial performance presented in accordance with GAAP or as a measure of a company's profitability or liquidity, and may not be comparable to similarly titled measures used by other companies.

Explanation and Reconciliation of Non-GAAP Financial Measures
Discretionary Cash Flow ($ millions):
Three Months EndedTwelve Months Ended
12/31/201112/31/2011
Net cash provided by operating activities $ 84.0 $ 455.9
Add back: Net increase (decrease) in current assets (0.6 ) 26.3
Add back: Net decrease (increase) in current liabilities including book overdraft 50.2 (20.3 )
Discretionary cash flow $ 133.6 $ 461.9
Adjusted Net Earnings ($ millions):
Three MonthsTwelve Months
EndedEnded
12/31/201112/31/2011
Adjusted net earnings $ 42.2 $ 149.1
After tax adjustments:
Non-cash derivative gain (loss) (68.5 ) 17.9
Impairment - oil & gas properties (387.6 ) (385.3 )
Extinguishment of debt and other (0.8 ) (9.8 )
Net loss, as reported $ (414.7 ) $ (228.1 )
Operating Margin Per BOE:

Three Months Ended

Twelve Months Ended

12/31/201112/31/2011
Average sales price including cash derivative settlements $ 68.80 $ 65.68
Operating cost - oil and gas production 18.11 18.23
Production taxes 2.64 2.58
Operating margin $ 48.05 $ 44.87
Pre-tax PV10 ($ millions):
12/31/201112/31/2010
Standardized measure of oil and gas $ 4,035 $ 2,799
Discounted future cash flow from income taxes 1,670 1,035
Discounted future net cash flow before income taxes $ 5,705 $ 3,834

Teleconference Call

An earnings conference call will be held Thursday, February 23, 2012 at 1:00 p.m. Eastern Time (11:00 a.m. Mountain Time). Dial 800-561-2693 to participate, using passcode 94699758. International callers may dial 617-614-3523. For a digital replay available until March 1, 2012 dial 888-286-8010 passcode 13336969. 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,” “potential,” 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, resources, 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 EndedTwelve Months Ended
12/31/20119/30/201112/31/201112/31/2010
REVENUES
Sales of oil and gas $ 227,298 $ 225,325 $ 870,773 $ 619,608
Sales of electricity 10,750 9,826 34,953 34,740
Natural gas marketing 2,550 3,612 13,832 22,162
Settlement of Flying J bankruptcy claim 21,992
Interest and other income, net 391 463 1,784 3,300
240,989 239,226 921,342 701,802
EXPENSES
Operating costs - oil and gas production 59,634 61,979 237,476 190,218
Operating costs - electricity generation 5,720 6,965 25,690 31,295
Production taxes 8,691 9,185 33,617 22,999
Depreciation, depletion & amortization - oil and gas production 55,202 54,581 213,859 179,432
Depreciation, depletion & amortization - electricity generation 484 487 1,963 3,225
Natural gas marketing 2,563 3,285 13,038 19,896
General and administrative 14,604 14,922 61,727 52,846
Interest 19,512 19,928 72,807 66,541
Extinguishment of debt 1,152 14,391 15,544 573
Realized and unrealized (gain) loss on derivatives, net 112,529 (162,145 ) (13,908 ) 31,847
Gain on purchase (1,046 )
Transaction costs on acquisitions 2,635
Impairment of oil and gas properties 625,564 625,564
Dry hole, abandonment, impairment and exploration 4,685 196 5,302 2,311
Bad debt recovery (38,508 )
910,340 23,774 1,291,633 565,310
Earnings (loss) before income taxes (669,351 ) 215,452 (370,291 ) 136,492
Income tax provision (benefit) (254,618 ) 81,451 (142,228 ) 53,968
Net earnings (loss) $ (414,733 ) $ 134,001 $ (228,063 ) $ 82,524
Basic net earnings (loss) per share $ (7.62 ) $ 2.45 $ (4.21 ) $ 1.54
Diluted net earnings (loss) per share $ (7.62 ) $ 2.42 $ (4.21 ) $ 1.52
Dividends per share $ 0.080 $ 0.080 $ 0.310 $ 0.300
CONDENSED BALANCE SHEETS
(In thousands)
(unaudited)
12/31/201112/31/2010
ASSETS
Current assets 167,634 142,866
Oil and gas properties, buildings and equipment, net 2,531,393 2,655,792
Derivative instruments 7,027 2,054
Other assets 28,898 37,904
$ 2,734,952 $ 2,838,616
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities 231,173 270,651
Deferred income taxes 185,450 329,207
Long-term debt 1,380,192 1,108,965
Derivative instruments 15,505 33,526
Other long-term liabilities 81,903 71,714
Shareholders’ equity 840,729 1,024,553
$ 2,734,952 $ 2,838,616
CONDENSED STATEMENTS OF CASH FLOWS
(In thousands)
(unaudited)
Three Months EndedTwelve Months Ended
12/31/20119/30/201112/31/201112/31/2010
Cash flows from operating activities:
Net (loss) earnings $ (414,733 ) $ 134,001 $ (228,063 ) $ 82,524
Depreciation, depletion and amortization 55,686 55,068 215,822 182,657
Gain on purchase (1,046 )
Extinguishment of debt 695 3,377 4,072 573
Amortization of debt issuance costs and net discount 1,982 2,056 8,243 8,481
Impairment of oil and gas properties 625,564 625,564
Dry hole and impairment 4,300 18 4,616 1,478
Derivatives 110,589 (159,179 ) (29,094 ) 42,609
Stock-based compensation expense 2,185 2,012 9,636 9,386
Deferred income taxes (254,375 ) 85,524 (149,279 ) 54,698
Other, net 1,577 972 3,223 (12 )
Cash paid for abandonment 118 (1,057 ) (1,803 ) (1,832 )
Allowance for bad debt (38,508 )
Change in book overdraft (5,515 ) 1,337 (156 ) 528
Net changes in operating assets and liabilities (44,064 ) 41,239 (5,836 ) 24,655
Net cash provided by operating activities 84,009 165,368 455,899 367,237
Cash flows from investing activities:
Exploration and development of oil and gas properties (102,968 ) (152,711 ) (527,112 ) (310,139 )
Property acquisitions (2,647 ) (9,982 ) (158,090 ) (334,409 )
Capitalized interest (4,881 ) (5,572 ) (29,117 ) (28,321 )
Deposits on asset sales 3,300 3,300
Net cash used in investing activities (107,196 ) (168,265 ) (711,019 ) (672,869 )
Net cash provided by financing activities 23,391 2,743 255,140 300,599
Net increase (decrease) in cash and cash equivalents 204 (154 ) 20 (5,033 )
Cash and cash equivalents at beginning of period 94 248 278 5,311
Cash and cash equivalents at end of period $ 298 $ 94 $ 298 $ 278
COMPARATIVE OPERATING STATISTICS (unaudited)
Three Months EndedTwelve Months Ended
12/31/20119/30/2011Change12/31/201112/31/2010Change
Oil and gas:
Heavy oil production (BOE/D) 17,497 18,173 17,397 17,124
Light oil production (BOE/D) 8,166 7,918 7,374 4,589
Total oil production (BOE/D) 25,663 26,091 24,771 21,713
Natural gas production (Mcf/D) 60,759 64,950 65,498 65,720
Total (BOE/D) 35,790 36,916 35,687 32,666
Oil and gas, per BOE:
Average realized sales price $ 69.29 $ 66.74 4 % $ 66.91 $ 52.14 28 %
Average sales price including cash derivative settlements 68.80 67.62 2 % 65.68 53.84 22 %
Oil, per BOE:
Average WTI price $ 94.06 $ 89.48 5 % $ 95.11 $ 79.59 19 %
Price sensitive royalties (3.63 ) (3.37 ) (3.60 ) (3.06 )
Quality differential and other 4.75 4.45 0.84 (8.92 )
Oil derivatives non-cash amortization (6.76 ) (6.56 ) (6.77 ) (2.59 )
Oil revenue per BOE $ 88.42 $ 84.00 5 % $ 85.58 $ 65.02 32 %
Add: Oil derivatives non-cash amortization 6.76 6.56 6.77 2.59
Oil derivative cash settlements (8.89 ) (6.32 ) (9.72 ) (0.90 )
Average realized oil price $ 86.29 $ 84.24 2 % $ 82.63 $ 66.71 24 %

Natural gas price:
Average Henry Hub price per MMBtu $ 3.54 $ 4.20

(16

)%

$ 4.04 $ 4.39 (8 )%
Conversion to Mcf 0.21 0.21 0.28 0.22
Natural gas derivatives non-cash amortization 0.02 0.01 0.08
Location, quality differentials and other (0.24 ) (0.18 ) (0.23 ) (0.24 )
Natural gas revenue per Mcf $ 3.51 $ 4.25 (17 )% $ 4.10 $ 4.45 (8 )%
Natural gas derivatives non-cash amortization (0.02 ) (0.01 ) (0.08 )
Natural gas derivative cash settlements 0.61 0.42 0.46 0.37
Average realized natural gas price per Mcf $ 4.12 $ 4.65 (11 )% $ 4.55 $ 4.74 (4 )%
Operating cost - oil and gas production $ 18.11 $ 18.25 (1 )% $ 18.23 $ 15.95 14 %
Production taxes 2.64 2.70 2.58 1.93
Total operating costs $ 20.75 $ 20.95 (1 )% $ 20.81 $ 17.88 16 %
DD&A - oil and gas production 16.77 16.07 4 % 16.42 15.05 9 %
General & administrative 4.44 4.39 1 % 4.74 4.43 7 %
Interest expense $ 5.93 $ 5.87 1 % $ 5.59 $ 5.58 %

Contacts:

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