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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934.
For the quarterly period ended March 31, 2004
Commission file number 1-9735
BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0079387
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5201 Truxtun Avenue, Suite 300, Bakersfield, California 93309-0640
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (661) 616-3900
Former name, Former Address and Former Fiscal Year, if Changed Since
Last Report:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or such shorter period that
the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
YES (X) NO ( )
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). YES (X) NO ( )
The number of shares of each of the registrant's classes of capital
stock outstanding as of March 31, 2004, was 20,925,096 shares of Class
A Common Stock ($.01 par value) and 898,892 shares of Class B Stock
($.01 par value). All of the Class B Stock is held by a shareholder
who owns in excess of 5% of the outstanding stock of the registrant.
BERRY PETROLEUM COMPANY
MARCH 31, 2004
INDEX
Page
No.
PART I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets at March 31, 2004 and
December 31, 2003 3
Condensed Income Statements for the Three Month Periods
Ended March 31, 2004 and 2003 4
Condensed Statements of Comprehensive Income for the
Three Month Periods Ended March 31, 2004 and 2003 4
Condensed Statements of Cash Flows for the
Three Month Periods Ended March 31, 2004 and 2003 5
Notes to Condensed Financial Statements 6
Item 2. Management's Discussion and Analysis
Of Financial Condition and Results of Operations 7
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 11
Item 4. Controls and Procedures 12
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 13
SIGNATURE 14
Certification of Chief Executive Officer 15
Certification of Chief Financial Officer 16
2
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets
(In Thousands, Except Share Information)
March December
31, 31,
2004 2003
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 9,383 $ 10,658
Short-term investments available for sale 665 663
Accounts receivable 26,722 23,506
Deferred income taxes 4,858 4,410
Prepaid expenses and other 2,149 2,049
_________ _________
Total current assets 43,777 41,286
Oil and gas properties (successful efforts
basis), buildings and equipment, net 306,545 295,151
Other assets 2,174 1,755
_________ _________
$ 352,496 $ 338,192
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 31,315 $ 32,490
Accrued liabilities 4,678 4,214
Federal and state income taxes payable 6,360 4,238
Fair value of derivatives 6,088 5,710
_________ _________
Total current liabilities 48,441 46,652
========= =========
Long-term liabilities:
Deferred income taxes 40,797 38,168
Long-term debt 50,000 50,000
Abandonment obligation 7,369 7,311
Other - 343
_________ _________
Total long-term liabilities 98,166 95,822
Shareholders' equity:
Preferred stock, $.01 par value;
2,000,000 - -
shares authorized; no shares outstanding
Capital stock, $.01 par value:
Class A Common Stock, 50,000,000 shares
authorized; 20,925,096 shares issued
and
outstanding at March 31, 2004 209 209
(20,904,372
at December 31, 2003)
Class B Stock, 1,500,000 shares
authorized;
898,892 shares issued and outstanding 9 9
(liquidation preference of $899)
Capital in excess of par value 49,847 49,798
Deferred Stock Option Compensation (111) ( 120)
Accumulated other comprehensive loss (3,267) (3,632)
Retained earnings 159,202 149,454
_________ __________
Total shareholders' equity 205,889 195,718
_________ __________
$ 352,496 $ 338,192
========= =========
The accompanying notes are an integral part of these financial
statements.
3
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Income Statements
Three Month Periods Ended March 31, 2004 and 2003
(In Thousands, Except Per Share Information)
(Unaudited)
2004 2003
Revenues:
Sales of oil and gas $ 45,205 $ 34,354
Sales of electricity 11,934 12,418
Interest and other income, net 203 20
__________ __________
57,342 46,792
__________ __________
Expenses:
Operating costs - oil and gas production 18,020 13,184
Operating costs - electricity generation 11,934 12,418
Depreciation, depletion and amortization 7,209 4,454
General and administrative 3,301 2,257
Dry hole, abandonment and impairment - 2,487
Interest 531 209
__________ __________
40,995 35,009
__________ __________
Income before income taxes 16,347 11,783
Provision for income taxes 4,198 2,606
__________ __________
Net income $ 12,149 $ 9,177
========== ==========
Basic net income per share $ .56 $ .42
========== ==========
Diluted net income per share $ .55 $ .42
========== ==========
Cash dividends per share $ .11 $ .10
========== ==========
Weighted average number of shares
of capital stock outstanding used to
calculate basic net income per share 21,817 21,758
Effect of dilutive securities: __________ __________
Stock options 404 120
Other 52 42
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 22,273 21,920
========== ==========
Condensed Statements of Comprehensive Income
Three Month Periods Ended March 31, 2004 and 2003
(in Thousands)
(Unaudited)
2004 2003
Net income $ 12,149 $ 9,177
Unrealized gains (losses) on derivatives,
(net of income taxes of $243 and $(1,422),
respectively) 364 (2,133)
__________ __________
Comprehensive income $ 12,513 $ 7,044
========== ==========
The accompanying notes are an integral part of these financial
statements.
4
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Statements of Cash Flows
Three Month Periods Ended March 31, 2004 and 2003
(In Thousands)
(Unaudited)
2004 2003
Cash flows from operating activities:
Net income $ 12,149 $ 9,177
Depreciation, depletion and amortization 7,209 4,454
Dry hole, abandonment and impairment (105) 2,487
Deferred income tax liability 2,372 913
Other, net 146 59
(Increase) in current assets other than
cash, cash equivalents and short-term (3,614) (5,287)
investments
Increase(decrease)in current liabilities 1,409 (3,444)
__________ __________
Net cash provided by operating 19,566 8,359
activities
Cash flows from investing activities:
Capital expenditures (18,440) (2,324)
Property acquisitions - (2,547)
__________ __________
Net cash used in investing activities (18,440) (4,871)
Cash flows from financing activities:
Dividends paid (2,401) (2,175)
__________ __________
Net cash used in financing activities (2,401) (2,175)
__________ __________
Net (decrease)increase in cash and cash
equivalents (1,275) 1,313
Cash and cash equivalents at beginning of
year 10,658 9,866
__________ __________
Cash and cash equivalents at end of $ 9,383 $ 11,179
period ========== ==========
Supplemental non-cash activity:
Increase(decrease) in fair value of
derivatives:
Current (net of income taxes of $(151) and
$(1,363) in 2004 and 2003, respectively) $ (227) $ (2,045)
Non-current (net of income taxes of $394
and $(59) in 2004 and 2003, respectively) 591 (88)
Net increase (decrease) to accumulated __________ __________
other comprehensive income $ 364 $ (2,133)
========== ==========
The accompanying notes are an integral part of these financial
statements.
5
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
March 31, 2004
(Unaudited)
1. All adjustments which are, in the opinion of Management,
necessary for a fair presentation of the Company's financial
position at March 31, 2004 and December 31, 2003 and results of
operations and cash flows for the three-month periods ended March
31, 2004 and 2003 have been included. All such adjustments are
of a normal recurring nature. The results of operations and cash
flows are not necessarily indicative of the results for a full
year.
2. The accompanying unaudited financial statements have been
prepared on a basis consistent with the accounting principles and
policies reflected in the December 31, 2003 financial statements.
The December 31, 2003 Form 10-K should be read in conjunction
herewith. The year-end condensed balance sheet was derived from
audited financial statements, but does not include all
disclosures required by accounting principles generally accepted
in the United States of America.
3. As allowed in Statement of Financial Accounting Standards
(SFAS) No. 123, "Accounting for Stock-Based Compensation," as
amended, the Company continues to apply Accounting Principles
Board Opinion (APB) No. 25, "Accounting for Stock Issued to
Employees," and associated interpretations in recording
compensation related to its stock option plan.
Under SFAS No. 123, as amended, compensation cost would be
recognized for the fair value of the employee's option rights.
Had compensation cost for the Company's stock based compensation
plan been based upon the fair value at the grant dates for awards
under the plan consistent with SFAS No. 123, as amended, using
the Black-Scholes Method, the Company's compensation cost, net of
related tax effects, net income and earnings per share would have
been recorded as the proforma amounts indicated below for the
three months ended March 31, 2004 and 2003 (in thousands, except
per share data):
2004 2003
Compensation cost, net of income
taxes
As reported $ 199 $ 20
Pro forma 320 151
Net income:
As reported 12,149 9,177
Pro forma 12,028 9,046
Basic net income per share:
As reported .56 .42
Pro forma .55 .42
Diluted net income per share:
As reported .55 .42
Pro forma .54 .41
6
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations
The Company earned a record net income of $12.1 million, or
$.55 per share (diluted), on revenues of $57.3 million in the
first quarter of 2004, up 32% from net income of $9.2 million, or
$.42 per share (diluted), in the first quarter of 2003, and up
14% from net income of $10.6 million, or $.48 per share
(diluted), in the fourth quarter of 2003. Results in the first
quarter of 2003 included an after-tax charge of $1.4 million,
representing the cost of an unsuccessful pilot coalbed methane
project and associated leasehold acquisition costs in Kansas.
The following table presents certain comparative operating
data for the first quarters of 2004 and 2003 and the fourth
quarter of 2003.
Three Months Ended
Mar 31, Mar 31, Dec 31,
2004 2003 2003
Oil and gas:
Net production - BOE/day 19,395 15,736 18,550
Per BOE:
Average sales price, net of hedges (1) $ 25.58 $ 24.23 $ 22.68
Operating costs (2) 9.24 8.78 8.30
Production taxes .97 .53 .70
Total operating costs 10.21 9.31 9.00
Depreciation, depletion and
amortization (DD&A) 4.08 3.15 3.61
General and administrative expenses(G&A) 1.87 1.59 1.71
Interest expense .30 .15 .33
Electricity:
Electric power produced - MWh/day 2,167 2,137 2,101
Electric power sold - MWh/day 1,956 1,951 1,964
Average sales price, net of hedges - $/MWh 67.05 70.71 62.20
Fuel gas cost - $/MMBtu 5.09 5.40 4.37
(1)Comparative average West Texas
Intermediate (WTI) price $ 35.25 $ 33.80 $ 31.16
(2)Includes monthly expenses in excess of
monthly revenues from cogeneration 1.81 1.72 1.55
operations
BOE = Barrels of Oil Equivalent
The Company's production of oil and gas (BOE/day) in the
first quarter of 2004 improved to 19,395, up 23% from 15,736 in
the first quarter of 2003 and up 5% from 18,550 in the fourth
quarter of 2003. Increased production is due primarily to the
acquisition of the Brundage Canyon property in Utah in August
2003 and the subsequent development thereof. At Brundage Canyon,
the Company drilled 27 new wells during 2003 and 14 new wells
during the first quarter of 2004. Production from Brundage
Canyon averaged approximately 2,100 BOE per day during the fourth
quarter of 2003, increasing to approximately 3,200 BOE per day
during the first quarter of 2004. To date, the performance of
new wells has
7
exceeded Management's expectations with current net
production from the field at approximately 3,700 BOE per day.
The Company plans to drill, at a minimum, an additional 30 wells
at Brundage Canyon during 2004.
Production from the Company's California properties in the
first quarter of 2004 remained strong and was within 1% of the
record production of 16,164 BOE per day in the fourth quarter of
2003. The Company plans to drill a total of 44 wells on its
California properties in 2004. With production increases
projected from the Company's Brundage Canyon and California
properties, Management is targeting total production in 2004 to
exceed 20,500 BOE per day, up approximately 24% from 2003.
The average price received per BOE, net of hedges, for the
Company's crude oil in the first quarter of 2004 was $25.58 per
barrel, up 6% from $24.23 per barrel received in the first
quarter of 2003 and up 13% from $22.68 per barrel received in the
fourth quarter of 2003.
The Company has continued its practice of hedging a portion
of its production to protect cash flows from severe revenue price
declines. See "Item 3. Quantitative and Qualitative Disclosures
About Market Risk" for information related to these agreements
and their impact on future revenues. The Company nets its oil
hedging gains or losses into its revenue from the sale of oil and
gas. For the first quarter of 2004, the effect of these
agreements was to reduce the net realized price of crude oil by
$2.68 per barrel compared to a reduction of $2.62 per barrel in
the first quarter of 2003 and $1.91 per barrel in the fourth
quarter of 2003. The Company did not enter into any new
hedging arrangements in the first quarter of 2004.
The Company sells approximately 85 MW of electricity from
its cogeneration facilities. Approximately 65 MW is sold to
utilities under Standard Offer (SO) contracts that are scheduled
to terminate on December 31, 2004. In January 2004, the
California Public Utility Commission (CPUC) issued a decision
that orders the utilities to continue to purchase energy and
capacity from Qualified Facilities (QFs), such as Berry, under 5-
year SO contracts. The CPUC recently initiated a rulemaking to
determine the price that will be paid under these SO contracts.
The Company is carefully reviewing this and other options for the
sale of energy beginning in 2005. The remaining 20 MW of
electricity continues to be sold to a utility under a long-term
SO contract that is scheduled to terminate in March 2009.
Operating costs for the first three months of 2004 of $18.0
million were up 37% from $13.2 million in the first quarter of
2003 due primarily to the addition of a new core area in Utah.
The operating costs in the first quarter of 2004 were up $2.6
million, or 17%, from $15.4 million in the fourth quarter of 2003
due primarily to increased steam costs.
Operating costs on a per BOE basis in Utah are lower than in
California due primarily to steam costs incurred to produce heavy
crude oil in California. Companywide, the increase on a per BOE
basis from the first quarter of 2003 to the first quarter of 2004
was due primarily to higher steam costs resulting from a 10%
increase in injected steam volumes. The increase on a per BOE
basis from the fourth quarter of 2003 to the first quarter of
2004 was also related to higher steam costs, in this case, due to
higher fuel costs. The Company anticipates operating costs to
average between $9.50 and $10.50 per BOE in 2004.
8
DD&A for the first quarter of 2004 was $7.2 million, up 62%
from $4.5 million in the first quarter of 2003 and up 17% from
$6.2 million in the fourth quarter of 2003. DD&A was higher due
to the acquisition of the Brundage Canyon properties in 2003 and
the cumulative effect of development activities in recent years.
On a per BOE basis, DD&A was $4.08 in the first quarter of 2004,
up from $3.15 and $3.61 in the first quarter of 2003 and fourth
quarter of 2003, respectively. The Company anticipates its
average DD&A rate for 2004 will approximate $3.80 to $4.20 per
BOE.
G&A for the first quarter of 2004 was $3.3 million, or
$1.87 per BOE, up 46% from $2.3 million, or $1.59 per BOE, in the
first quarter of 2003 and up 14% from $2.9 million, or $1.71 per
BOE, in the fourth quarter of 2003. The increase in the first
quarter of 2004 was due primarily to higher compensation related
costs. For 2004, the Company expects G&A costs of approximately
$12.0 million to $13.5 million with the primary variable being
the quantity of stock option exercises. The Company estimates
G&A costs to range from $1.60 to $1.80 per BOE in 2004.
The Company experienced an effective tax rate of 26% for the
first quarter of 2004 compared to 22% for the same period last
year. The Company continues to invest in qualifying enhanced oil
recovery (EOR) projects. However, the anticipated EOR credit in
2004 relative to higher pre-tax income resulting from higher oil
prices and increased production resulted in a higher effective
tax rate compared to the 2003 period. Based on current oil
prices, the Company anticipates an effective tax rate for 2004
between 26% and 30%.
Liquidity and Capital Resources
Working capital as of March 31, 2004 was negative $4.7
million, down from $6.8 million as of March 31, 2003 and up from
a negative $5.4 million as of December 31, 2003. Net cash
provided by operating activities was $19.6 million in the first
quarter of 2004, up from $8.4 million in the first quarter of
2003 due to higher production levels resulting from the
acquisition of Brundage Canyon, improved production on California
properties and increases in oil prices, and down from $24.8
million in the fourth quarter of 2003 due primarily to a $10.2
million payment in the first quarter of 2004 for an annual price-
based royalty on a Company property.
Cash was also used to fund $18.4 million in capital
expenditures in the first quarter of 2004 which included drilling
35 new wells and completing 17 workovers. Of these totals, 21
new wells were drilled and 9 workovers were performed in
California and 14 new wells were drilled and 8 workovers were
performed on the Brundage Canyon properties.
The Company plans to spend a total of approximately $53
million in 2004 on capital projects to drill a total of 44 new
wells and perform 63 workovers in California and to drill a total
of 44 new wells and perform 20 workovers in Brundage Canyon, and
drill an additional 7 wells and perform 2 workovers in other
Rocky Mountain and Mid-Continent properties. If WTI prices
remain above $30 per barrel, the Company may accelerate some
drilling projects. Excess cash will be targeted to acquisitions,
additional development and debt reduction.
9
Forward Looking Statements
"Safe harbor under the Private Securities Litigation Reform Act
of 1995:" With the exception of historical information, the
matters discussed in this Form 10-Q are forward-looking
statements that involve risks and uncertainties. Although the
Company believes that its expectations are based on reasonable
assumptions, it can give no assurance that its goals will be
achieved. Important factors that could cause actual results to
differ materially from those in the forward-looking statements
herein include, but are not limited to, the timing and extent of
changes in commodity prices for oil, gas and electricity, a
limited marketplace for electricity sales within California,
counterparty risk, competition, environmental risks, litigation
uncertainties, drilling, development and operating risks, the
availability of drilling rigs and other support services,
legislative and/or judicial decisions and other government
regulations.
10
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 3. Quantitative and Qualitative Disclosures About Market
Risk
The Company enters into various financial contracts to hedge
its exposure to commodity price risk associated with its crude
oil production, electricity production and net natural gas
volumes purchased for its steaming operations. These contracts
related to crude oil and natural gas have historically been in
the form of zero-cost collars and swaps. The Company generally
attempts to hedge between 25% and 50% of its anticipated crude
oil production each year and up to 30% of its anticipated net
natural gas purchased each year. All of these hedges have
historically been deemed to be cash flow hedges with the mark-to-
market valuations of the collars provided by external sources,
based on prices that are actually quoted.
Based on NYMEX futures prices as of March 31, 2004, (WTI
$33.82; Henry Hub (HH) $5.68) the Company would expect to make
pre-tax future cash payments over the remaining term of its crude
oil and natural gas hedges in place as follows:
Impact of percent change in
futures prices
on earnings
NYMEX
Futures -20% -10% 10% 20%
_______ ______ ______ _______ ______
Average WTI Price $33.82 $27.05 $30.44 $ 37.20 $40.58
Crude Oil gain/(loss) (in
thousands) (8,250) 350 (5,250) (11,140) (14,040)
Average HH Price $ 5.68 $ 4.54 $ 5.11 $ 6.25 $ 6.82
Natural Gas gain/(loss) (in
thousands) 2,230 (2,260) (10) 4,480 6,730
The Company sells 100% of its electricity production, net of
electricity used in its oil and gas operations, under SO
contracts to major utilities. Three of the four SO contracts
representing approximately 77% of the Company's electricity for
sale expired on December 31, 2003. However, as ordered by the
CPUC, these contracts have been extended through December 31,
2004 and the Company is evaluating its options beyond the revised
termination dates. Among other things, the CPUC issued a
decision in January 2004 that ordered the California utilities to
offer SO contracts to certain QFs, such as Berry, for a term of 5
years. The CPUC recently initiated a rulemaking to determine the
price that will be paid under these SO contracts. The Company
sells the remaining 20 MW to a utility at $53.70 per MWh plus
capacity through a long-term SO contract.
The Company attempts to minimize credit exposure to counter
parties through monitoring procedures and diversification. The
Company's exposure to changes in interest rates results primarily
from long-term debt. Total debt outstanding at both March 31,
2004 and December 31, 2003 was $50 million. Interest on amounts
borrowed is charged at LIBOR plus 1.25% to 2.0%. Based on these
borrowings, a 1% change in interest rates would not have a
material impact on the Company's financial statements.
11
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 4. Controls and Procedures
The Company's Management, with the participation of the
Company's Interim Chief Executive Officer and the Chief Financial
Officer, evaluated the effectiveness of the Company's disclosure
controls and procedures as of the end of the period covered by
this report. Based on that evaluation, the Interim Chief
Executive Officer and the Chief Financial Officer concluded that
the Company's disclosure controls and procedures as of the end of
the period covered by this report were designed and functioning
effectively to provide reasonable assurance that the information
required to be disclosed by the Company in reports filed under
the Securities Exchange Act of 1934, as amended, is recorded,
processed, summarized and reported within the time periods
specified in the SEC's rules and forms. No change in the
Company's internal control over financial reporting occurred
during the Company's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the Company's internal control over financial reporting.
12
BERRY PETROLEUM COMPANY
Part II. Other Information
PART II OTHER INFORMATION
(a) Exhibits
Exhibit No. Description
31.1 Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002. *
31.2 Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002. *
32.1 Certification of Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002. *
32.2 Certification of Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002. *
* Filed herewith
(b) Reports on Form 8-K
On January 13, 2004, the Company filed a Form 8-K reporting
an Item 9 - Regulation FD Disclosure to furnish the Securities and
Exchange Commission a copy of the Company's press release announcing the
board of directors approved a 2004 capital expenditure budget of
approximately $50 million.
On February 18, 2004, the Company filed a Form 8-K reporting
an Item 9 - Regulation FD Disclosure to furnish the Securities and
Exchange Commission a copy of the Company's press release announcing
financial results for the three months and fiscal year ended December
31, 2003.
On April 26, 2004, the Company filed a Form 8-K reporting an
Item 9 - Regulation FD Disclosure to furnish the Securities and Exchange
Commission a copy of the Company's press release announcing the
retirement of Jerry V. Hoffman as president and chief executive
officer, and the appointment of Robert F. Heinemann as Interim President
and Interim Chief Executive Officer.
13
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereto duly authorized on May 5, 2004.
BERRY PETROLEUM COMPANY
/s/ Donald A. Dale
Donald A. Dale
Controller
(Principal Accounting Officer)
Date: May 5, 2004
14