(Source: Business Wire)
Berry Petroleum Company (NYSE:BRY)
reported net income of $19 million, or $0.41 per diluted share, for the
third quarter of 2009, compared to net income of $53.3 million, or $1.16
per diluted share in the third quarter of 2008, according to Robert F.
Heinemann, president and chief executive officer. Discretionary cash
flow for the third quarter totaled $60 million. (Discretionary cash flow
is a non-GAAP measure; see reconciliation below.)
Items that affected net income for the quarter included a non-cash gain
on hedges, the write-off of certain costs related to the Company's
credit facility, a net gain on asset sales, and inventoried volumes from
Poso Creek that were sold in the third quarter. In total, for the third
quarter of 2009, these items increased net income by approximately $3.3
million, or $0.07 per diluted share for an adjusted third quarter net
income of $15.7 million, or $0.34 per diluted share.
For the third quarters of 2009 and 2008, average net production in BOE
per day was as follows:
Third Quarter Ended September 30
2009 Production 2008 Production
Oil (Bbls) 19,310 68 % 21,162 60 %
Natural Gas (BOE) 9,107 32 % 13,988 40 %
Total BOE per day 28,417 100 % 35,150 100 %
DJ Basin Production (BOE/D) - 3,337
Production -- Continuing Operations (BOE/D) 28,417 31,813
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Mr. Heinemann said, "Production averaged 28,400 BOE/D for the third
quarter of 2009 generating discretionary cash flow of $60 million with a
total of only $22 million of capital expenditures. Strong cash flow
along with the completion of our East Texas midstream sale allowed us to
repay $78 million of debt during the quarter. With our $938 million
borrowing base reconfirmed during October, our liquidity today is
approximately $550 million. As we complete our 2009 program, we are also
preparing for an increased level of activity in 2010. In the Diatomite
we are installing additional infrastructure and steam generation
capacity to prepare for our drilling program which should increase
production to 5,000 BOE/D by year-end 2010. During the fourth quarter we
will also initiate a steam flood pilot on our recently acquired
McKittrick 21Z property and expand our successful steam flood pilot at
Ethel D. These activities are supported by continued strong demand for
California crude oil which allowed us during the third quarter to
execute twelve month contracts for most of our California production."
Three Months Results
Sales from oil and gas were $127 million in the third quarter of 2009
compared to $194 million in the same 2008 period due primarily to lower
oil and natural gas prices. For the same period, operating costs were
lower by $2.94 per BOE due to lower natural gas prices which reduces the
cost of steam in California and the continued results of company-wide
cost reduction initiatives. General and administrative costs were also
lower by $0.78 per BOE as the Company continues to realize the benefits
of its cost reduction efforts. Interest expense was higher by $6.5
million compared to the third quarter of 2008 as a result of issuing
$450 million of 10.25% senior unsecured notes during the second and
third quarters of 2009.
Operational Update
Michael Duginski, executive vice president and chief operating officer,
stated, "Our operating cost reductions have remained solid with a 25%
reduction year to date compared to 2008 levels. These cost reductions,
along with a narrowed California crude oil differential, allowed us to
generate margins of approximately $28.75 per BOE during the third
quarter. Our N. Midway Diatomite production continues to perform as
expected averaging 3,120 BOE/D in the third quarter, up 50% from the
comparable 2008 quarter and up 7% from the second quarter of 2009. The
necessary land work in E. Texas has been completed and we plan to spud
our first horizontal Haynesville well in the Darco field in the fourth
quarter of 2009. During the third quarter, we also tested high volume
completions in the Piceance with a 25% improvement in our initial
production rate compared to our historical field average. We expect to
increase production in the fourth quarter of 2009 as we complete our
2009 capital program and continue to expect companywide production to
average 30,000 BOE/D in 2009."
Costs Per BOE and Updated 2009 Guidance
Anticipated range
Full-year 2009per BOE 3 mo. ended09/30/09 3 mo. ended09/30/08
Operating costs-oil and gas production $ 13.00 - 15.00 $ 14.99 $ 17.93
Production taxes 1.50 - 2.50 1.48 3.04
DD&A -- oil and gas production (1) 12.50 - 13.50 12.81 12.76
G&A 4.25 - 4.75 4.09 4.87
Interest expense 4.00 - 4.75 5.57 2.74
Total $ 35.25 - 40.50 $ 38.94 $ 41.34
(1) Full-year estimate includes both oil & gas and electricity
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2010 Capital and Production Guidance
While the Company is finalizing its 2010 capital plans, capital spending
for 2010 is expected to range between $220 million and $260 million.
This capital will likely be allocated approximately 65% to oil projects
to fund the Diatomite development, steamflood developments at McKittrick
21Z and Ethel D and drilling at Brundage Canyon. With this level of
investment, production should increase approximately 5% with strong
quarterly increases throughout the year.
Explanation and Reconciliation of Non-GAAP Financial Measures
Discretionary Cash Flow
Three Months Ended
09/30/09 09/30/08
Net cash provided by operating activities $ 89.2 $ 137.4
Add back: Net increase (decrease) in current assets 1.9 6.1
Add back: Net decrease (increase) in current liabilities including book overdraft (31.6 ) (12.4 )
Discretionary cash flow $ 59.5 $ 131.1
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Adjusted Net Income
Three Months Ended
09/30/09
Net income before adjustments $ 19.0
After tax adjustments:
Non-cash hedge gains (2.4 )
Poso Creek Inventory trade sales (1.0 )
Write off of credit facility costs 0.2
Net gain on asset sales (0.1 )
Adjusted net income $ 15.7
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Teleconference Call
An earnings conference call will be held Friday, October 30, 2009 at
10:00 a.m. Eastern Time (8:00 a.m. Mountain Time). Dial 1-866-788-0547
to participate, using passcode 28922960. International callers may dial
857-350-1685. For a digital replay available until November 6, 2009 dial
1-888-286-8010 (passcode 98141508). Listen live or via replay on the web
at http://www.bry.com.
Transcripts of this and previous calls may be viewed at www.bry.com
in the "Investor Center."
About Berry Petroleum Company
Berry Petroleum Company is a publicly traded independent oil and gas
production and exploitation company with operations in California, Utah,
Colorado and Texas. The Company uses itsweb site as a channel of
distribution of material company information. Financial and other
material information regarding theCompany 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 "expected," "project," 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 2008 Form 10-K filed with the Securities and Exchange Commission
on February 25, 2009 under the heading "Other Factors Affecting the
Company's Business and Financial Results," and updated in the Company's
Form 10-Q filings subsequent to that date.
CONDENSED STATEMENTS OF INCOME (continuing operations)
(In thousands)
(unaudited)
Three Months Nine Months
09/30/09 09/30/08 09/30/09 09/30/08
Revenues
Sales of oil and gas $ 127,455 $ 193,890 $ 374,117 $ 514,578
Sales of electricity 9,137 18,317 26,032 51,223
Gas marketing 5,217 13,284 17,646 28,046
Gain (loss) on commodity derivatives 531 701 6,565 (27 )
Gain (loss) on sale of assets 828 95 828 510
Interest and other income, net 287 747 1,375 2,509
Total 143,455 227,034 426,563 596,839
Expenses
Operating costs -- oil & gas 39,195 52,486 111,317 144,158
Operating costs -- electricity 6,892 13,706 22,071 45,620
Production taxes 3,874 8,912 14,411 20,663
Depreciation, depletion & amortization - oil & gas 33,502 37,354 104,271 87,462
Depreciation, depletion & amortization - electricity 951 646 2,938 1,991
Gas marketing 4,633 12,034 16,149 26,087
General and administrative 10,686 14,251 37,143 36,312
Interest 14,562 8,031 35,201 14,910
Loss on extinguishment of debt 329 - 10,823 -
Dry hole, abandonment, impairment & exploration 69 1,488 209 7,396
Total 114,693 148,908 354,533 384,599
Income before income taxes 28,762 78,126 72,030 212,240
Provision for income taxes 10,423 28,511 24,681 79,377
Income from continuing operations 18,339 49,615 47,349 132,863
(Loss) income from discontinued operations, net 668 3,733 (6,323 ) 12,657
Net income $ 19,007 $ 53,348 $ 41,026 $ 145,520
Basic net income from continuing operations per share $ 0.41 $ 1.10 $ 1.04 $ 2.95
Basic net income (loss) from discontinued operations per common share $ 0.01 $ 0.08 $ (0.14 ) $ 0.28
Basic net income per common share $ 0.42 $ 1.18 $ 0.90 $ 3.23
Diluted net income from continuing operations per share $ 0.40 $ 1.08 $ 1.03 $ 2.90
Diluted net income (loss) from discontinued operations per common share $ 0.01 $ 0.08 $ (0.14 ) $ 0.28
Diluted net income per common share $ 0.41 $ 1.16 $ 0.89 $ 3.18
Cash dividends per share $ 0.075 $ 0.075 $ 0.225 $ 0.225
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CONDENSED BALANCE SHEETS
(In thousands)
(unaudited)
09/30/09 12/31/08
Assets
Current assets $ 109,401 $ 189,080
Property, buildings & equipment, net 2,096,897 2,254,425
Fair value of derivatives 1,002 79,696
Other assets 33,245 19,182
$ 2,240,545 $ 2,542,383
Liabilities & Shareholders' Equity
Current liabilities $ 149,041 $ 260,625
Deferred taxes 250,045 270,323
Long-term debt 1,000,925 1,131,800
Other long-term liabilities 64,057 47,888
Fair value of derivatives 41,316 4,203
Shareholders' equity 735,161 827,544
$ 2,240,545 $ 2,542,383
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CONDENSED STATEMENTS OF CASH FLOWS
(In thousands)
(unaudited)
Nine Months
09/30/09 09/30/08
Cash flows from operating activities:
Net income $ 41,026 $ 145,520
Depreciation, depletion & amortization (DD&A) 109,397 98,579
Loss on debt issuance costs 10,823 -
Dry hole & impairment 9,643 6,858
Commodity derivatives 4,796 (8 )
Stock based compensation 7,054 6,653
Deferred income taxes 13,546 76,502
Gain on sale of asset 79 (510 )
Other, net (362 ) (1,500 )
Net changes in operating assets and liabilities (47,623 ) (846 )
Net cash provided by operating activities 148,379 331,248
Net cash provided by (used in) investing activities 12,111 (986,865 )
Net cash (used in) provided by financing activities (159,755 ) 655,360
Net increase in cash and cash equivalents 735 (257 )
Cash and cash equivalents at beginning of year 240 316
Cash and cash equivalents at end of period $ 975 $ 59
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COMPARATIVE OPERATING STATISTICS
(Unaudited)
Three Months
September 30,2009 % September 30,2008 % June 30,2009 %
Heavy Oil Production (Bbl/D) 16,780 59 17,264 49 16,822 57
Light Oil Production (Bbl/D) 2,530 9 3,898 11 3,085 11
Total Oil Production (Bbl/D) 19,310 68 21,162 60 19,907 68
Natural Gas Production (Mcf/D) 54,637 32 83,928 40 56,174 32
Total Production (BOE/D) 28,417 100 35,150 100 29,270 100
DJ Basin Production (BOE/D) - 3,337 -
Production -- Continuing Operations (BOE/D) 28,417 31,813 29,270
Oil and gas BOE for continuing operations:
Average sales price before hedging $ 45.41 $ 83.90 $ 39.34
Average sales price after hedging 46.39 67.04 45.74
Oil, per Bbl, for continuing operations:
Average WTI price $ 68.24 $ 118.22 $ 59.79
Price sensitive royalties (2.36 ) (5.30 ) (2.08 )
Quality differential and other (8.78 ) (10.80 ) (7.86 )
Crude oil hedges 0.87 (26.12 ) 8.91
Average oil sales price after hedging $ 57.97 $ 76.00 $ 58.76
Natural gas price for continuing operations:
Average Henry Hub price per MMBtu $ 3.39 $ 10.24 $ 3.51
Conversion to Mcf 0.17 0.51 0.18
Natural gas hedges 0.20 0.20 0.21
Location, quality differentials and other (0.28 ) (2.69 ) (0.72 )
Average gas sales price after hedging per Mcf $ 3.48 $ 8.26 $ 3.18
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A service of YellowBrix, Inc.
