Back to GetFilings.com
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, 2003
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, 2003, was 20,860,070 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, 2003
INDEX
Page No.
PART I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets at March 31, 2003 and
December 31, 2002 3
Condensed Income Statements for the Three Month Periods
Ended March 31, 2003 and 2002 4
Condensed Statements of Comprehensive Income for the
Three Month Periods Ended March 31, 2003 and 2002 4
Condensed Statements of Cash Flows for the
Three Month Periods Ended March 31, 2003 and 2002 5
Notes to Condensed Financial Statements 6
Item 2. Management's Discussion and Analysis
Of Financial Condition and Results of Operations 9
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 14
Item 4. Controls and Procedures 15
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 16
SIGNATURE 16
Certification of Chief Executive Officer 17
Certification of Chief Financial Officer 18
Exhibit Index 19
2
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets
(In Thousands, Except Share Information)
March 31, December 31,
2003 2002
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 11,179 $ 9,866
Short-term investments available for sale 660 660
Accounts receivable 20,583 15,582
Prepaid expenses and other 2,598 2,597
-------- --------
Total current assets 35,020 28,705
Oil and gas properties (successful efforts
basis), buildings and equipment, net 226,814 228,475
Other assets 876 893
-------- --------
$ 262,710 $ 258,073
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 15,792 $ 19,189
Accrued liabilities 3,346 6,470
Federal and state income taxes payable 5,689 2,612
Fair value of derivatives 3,408 4,123
-------- --------
Total current liabilities 28,235 32,394
Long-term liabilities:
Deferred income taxes 34,779 33,866
Long-term debt 15,000 15,000
Abandonment obligation 5,041 4,596
Fair value of derivatives 146 159
-------- --------
Total long-term liabilities 54,966 53,621
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; 20,860,070 shares issued
and outstanding at March 31, 2003
(20,852,695 at December 31, 2002) 209 209
Class B Stock, 1,500,000 shares
authorized; 898,892 shares issued and
outstanding (liquidation preference of
$899) 9 9
Capital in excess of par value 49,065 49,052
Accumulated other comprehensive loss (2,133) (2,569)
Retained earnings 132,359 125,357
-------- --------
Total shareholders' equity 179,509 172,058
-------- --------
$ 262,710 $ 258,073
======== ========
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, 2003 and 2002
(In Thousands, Except Per Share Information)
(Unaudited)
2003 2002
Revenues:
Sales of oil and gas $ 34,354 $ 19,678
Sales of electricity 12,880 7,314
Interest and other income, net 20 378
-------- --------
47,254 27,370
-------- --------
Expenses:
Operating costs - oil and gas production 13,184 8,086
Operating costs - electricity generation 12,880 6,983
Depreciation, depletion and amortization 4,454 3,992
General and administrative 2,257 1,862
Recovery of electricity receivables - (3,631)
Dry hole and abandonment 2,487 -
Interest 209 423
-------- --------
35,471 17,715
-------- --------
Income before income taxes 11,783 9,655
Provision for income taxes 2,606 1,035
-------- --------
Net income $ 9,177 $ 8,620
======== ========
Basic net income per share $ .42 $ .40
======== ========
Diluted net income per share $ .42 $ .40
======== ========
Cash dividends per share $ .10 $ .10
======== ========
Weighted average number of shares
of capital stock outstanding (used to
calculate basic net income per share) 21,758 21,732
Effect of dilutive securities:
Stock options 120 50
Other 42 29
-------- --------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 21,920 21,811
======== ========
Condensed Statements of Comprehensive Income
Three Month Periods Ended March 31, 2003 and 2002
(in Thousands)
(Unaudited)
2003 2002
Net income $ 9,177 $ 8,620
Unrealized losses on derivatives, (net of
income taxes of $1,422 and $1,193,
respectively) (2,133) (1,790)
-------- --------
Comprehensive income $ 7,044 $ 6,830
======== ========
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, 2003 and 2002
(In Thousands)
(Unaudited)
2003 2002
Cash flows from operating activities:
Net income $ 9,177 $ 8,620
Depreciation, depletion and amortization 4,454 3,992
Dry hole and abandonment 2,487 -
Deferred income tax liability 913 187
Other, net 59 59
-------- --------
Net working capital provided by
operating activities 17,090 12,858
Decrease (increase) in accounts
receivable, prepaid expenses and other (5,287) 7,565
Decrease in current liabilities (3,444) (3,936)
-------- --------
Net cash provided by operating activities 8,359 16,487
Cash flows from investing activities:
Capital expenditures (2,324) (4,333)
Property acquisitions (2,547) -
-------- --------
Net cash used in investing activities (4,871) (4,333)
Cash flows from financing activities:
Payment of long-term debt - (5,000)
Dividends paid (2,175) (2,173)
-------- --------
Net cash used in financing activities (2,175) (7,173)
-------- --------
Net increase in cash and cash equivalents 1,313 4,981
Cash and cash equivalents at beginning of
year 9,866 7,238
-------- --------
Cash and cash equivalents at end of period $ 11,179 $ 12,219
======== ========
Supplemental non-cash activity:
Decrease in fair value of derivatives:
Current (net of income taxes of $1,363
and $1,193 in 2003 and 2002, respectively) $ 2,045 $ 1,790
Non-current (net of income taxes of $59
and $0 in 2003 and 2002, respectively) 88 -
-------- --------
Net decrease to accumulated other
comprehensive income $ 2,133 $ 1,790
======== ========
5
The accompanying notes are an integral part of these financial
statements.
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
March 31, 2003
(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, 2003 and December 31, 2002 and results of
operations and cash flows for the three month periods ended March
31, 2003 and 2002 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, 2002 financial statements.
The December 31, 2002 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. The Company has leased approximately 208,000 acres in Kansas
and 54,000 acres in Illinois for the purpose of exploring for
economic concentrations of coalbed methane for a total lease cost
of approximately $6.0 million. The Company drilled a five-well
pilot on the Illinois acreage in the fourth quarter of 2002
which, as anticipated, continues to dewater. The results of this
pilot are not yet conclusive and are not expected to be known
until the latter half of 2003. An additional five-well pilot was
drilled in the Wabaunsee County portion of the Kansas acreage
late in the fourth quarter of 2002. On this pilot, initial water
production was less than expected with no resulting gas pressure
buildup and the gas content of the coals was significantly lower
than anticipated. Consequently, the Company believes this pilot
will not produce commercial quantities of natural gas and,
therefore, wrote off the cost to drill the five-well pilot and
the associated leased acreage. The total amount charged to
operations in the first quarter of 2003 was $2.5 million. The
leased acreage in Kansas also includes acreage positions in
Jackson County and Osage County. The Company is evaluating the
location and method of drilling additional test wells in these
areas.
4. As allowed in Statement of Financial Accounting Standards
(SFAS) No. 123, "Accounting for Stock-Based Compensation," the
Company continues to apply Accounting Principles Board Opinion
(APB) No. 25, "Accounting for Stock Issued to Employees," and
related interpretations in recording compensation related to its
plan. The supplemental disclosure requirements of SFAS No. 123,
as amended in SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure," related to the
Company's stock option plan is presented below:
6
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
4. (cont'd) Under SFAS No. 123, compensation cost would be
recognized for the fair value of the employee's option rights.
The fair value of each option was estimated on the date of grant
using the Black-Scholes option-pricing model with the following
assumptions for option grants made in 2002 (there were no grants
issued in the first quarter of 2003):
2002
Yield 2.55%
Expected option life - 7.5
years
Volatility 33.45%
Risk-free interest rate 4.09%
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 the method of
SFAS No. 123 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, 2003
and 2002 (in thousands, except per share data):
2003 2002
Compensation cost, net of income
taxes
As reported $ 20 $ 5
Pro forma 151 161
Net income:
As reported 9,177 8,620
Pro forma 9,046 8,464
Basic net income per share:
As reported .42 .40
Pro forma .42 .39
Diluted net income per share:
As reported .42 .40
Pro forma .41 .39
The Company continues to evaluate the best method for fair-
market value pricing of stock options as there is no universal
acceptance of the Black Scholes Method as the most appropriate
method for companies such as Berry.
7
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
5. In April 2003, the Company entered into a Purchase and Sale
Agreement with Williams Production RMT Company to acquire its
Brundage Canyon, Utah properties in the Uinta Basin for
approximately $49 million. The Company anticipates the
acquisition will close in the third quarter of 2003. The
Brundage Canyon properties, located in northeastern Utah, consist
of approximately 43,500 net acres, and are currently producing
approximately 2,200 net BOE/day of light crude oil and natural
gas and the Company estimates the proved reserves at 8.6 million
BOE (75% light oil and 25% natural gas). The Company expects to
fund the acquisition from cash generated from operations and
borrowings from its credit facility.
8
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 net income of $9.2 million, or $.42 per
share, on revenues of $47.3 million in the first quarter of 2003,
up 7% from net income of $8.6 million, or $.40 per share, in the
first quarter of 2002, and up 31% from net income of $7 million,
or $.32 per share, in the fourth quarter of 2002. Results in the
first quarter of 2003 include a pre-tax write off of $2.5
million, representing the cost of a pilot project and associated
leasehold acquisition costs in Kansas. The results in the first
quarter of 2002 include the pre-tax gain from the recovery of a
$3.6 million receivable for electricity sales which was written
off in 2001.
The following table presents certain comparative operating
data for the first quarters of 2003 and 2002 and the fourth
quarter of 2002.
Three Months Ended
Mar 31, Mar 31, Dec 31,
2003 2002 2002
Oil and gas:
Net production - BOE/day 15,736 13,799 15,208
Per BOE:
Average sales price $ 24.23 $ 15.87 $ 20.41
Operating costs(1) 8.78 5.95 9.57
Production taxes .53 .56 .60
Total operating costs 9.31 6.51 10.17
Depreciation, depletion and
amortization (DD&A) 3.15 3.21 2.90
General and administrative
expenses(G&A) 1.59 1.50 1.26
Interest expense .15 .34 .13
Electricity:
Electric power produced - Mwh/day 2,137 2,051 2,126
Electric power sold - Mwh/day 1,951 1,890 1,860
Average sales price - $/Mwh $ 73.39 $ 36.35 $ 43.97
Fuel gas cost - $/MMBtu 5.40 2.49 3.99
(1)Including monthly expenses in excess of
monthly revenues from cogeneration
operations of $1.72, $.31 and $2.97 in the
three months ended March 31, 2003,
March 31, 2002 and December 31, 2002,
respectively.
Operating income from oil and gas operations in the first
quarter of 2003 was $14.3 million, up 86% from $7.7 million in
the first quarter of 2002 and up 36% from $10.5 million in the
fourth quarter of 2002.
Operating income increased in the first quarter of 2003 due
to increased crude oil production and higher crude oil and
electricity sales prices. These factors were offset somewhat by
higher fuel gas prices, higher DD&A and higher G&A costs.
9
The Company's production of oil and gas (BOE/day) in the
first quarter of 2003 improved to 15,736, up 14% from 13,799 in
the first quarter of 2002 and up 3% from 15,208 in the fourth
quarter of 2002. Production in the first quarter of 2002 had not
yet recovered from the effects of the temporary suspension of
steaming operations in 2001 due to the effects of the California
energy crisis. The Company injected approximately 60,000 barrels
of steam per day in 2002. This factor and the contribution of
the wells drilled and workovers completed under the 2002 capital
budget account for the majority of the increase in production
from the first quarter of 2002. Assuming stable natural gas and
crude oil prices and with the completion of the 2003 budget, the
Company's target is to average approximately 16,400 BOE/day for
the year with a 2003 exit rate of approximately 17,700 BOE/day.
The average price received for the Company's heavy crude oil
in the first quarter of 2003 was $24.23 per barrel, up 53% and
19% from the first quarter of 2002 and the fourth quarter of
2002, respectively.
The Company primarily uses zero-cost bracketed collars based
on WTI crude oil prices to protect cash flow from a severe crude
oil price decline. At March 31, 2003, the Company had hedged
6,500 barrels per day for the remainder of 2003 whereby the
Company could capture an average of $3.88 below a WTI price of
$22.31 per barrel and may give up to an average of $4.48 above
$25.79 per barrel. The Company has also hedged 5,000 barrels per
day in the first quarter of 2004 and 4,000 barrels per day for
the second through fourth quarters of 2004. In 2004, the Company
could capture up to an average of $3.64 per barrel below
approximately $22.39 per barrel and may give up to an average of
$4.24 per barrel above $25.65 per barrel. In addition to these
collars, the Company entered into a series of crude oil swaps
based on WTI pricing on 1,500 barrels per day at prices ranging
from $25.68 to $27.17 covering the six month period from May 1,
2003 to October 31, 2003 and 1,000 barrels per day for the six
months beginning November 2003 for an average price of $25.00.
The Company nets its oil hedging gains or losses into its
revenues from the sales of oil and gas.
On March 1, 2002, the Company received payment in full for
certain past due receivables from Southern California Edison
Company which were previously written off by the Company in 2001.
The Company recognized pre-tax gains from the recovery of $3.6
million of the receivables, $.1 million in additional
interest and $.5 million in additional capacity revenue for
periods in 2001 when the Company was compelled to shut-in its
cogeneration plants due to the payment default of the utility.
In January 2003, Standard Offer contract terms were
reinstated on the power produced from one of two turbines at the
Company's cogeneration facility located in the Placerita oilfield
in Los Angeles County and on both the 38 megawatt and 18 megawatt
facilities located on the Company's Midway-Sunset properties in
Kern County, California. Under the terms of these agreements,
the Company received an average of $72.89 per Mwh in the first
quarter of 2003. The primary benefit of these contracts is that
the Company's electricity revenues are based on the cost of
natural gas. Therefore, these contracts mitigate the Company's
exposure to higher operating costs based on higher natural gas
costs. The Company consumes approximately 37,000 MMBtu of
natural gas per day for use in generating steam and of this
total, approximately 72% is consumed in the Company's
cogeneration operations.
10
Operating expenses for the first three months of 2003 were
$13.2 million, up 63% from $8.1 million, in the first quarter of
2002, but down 7% from $14.2 million in the fourth quarter of
2002. The cost of natural gas used in the Company's steaming
operations increased from $2.49 per MMBtu in the first quarter of
2002 to $5.40 in the first quarter of 2003, resulting in
significantly higher steam costs in the 2003 quarter compared to
the first quarter of 2002. The cost of natural gas per MMBtu was
$5.40 in the first quarter of 2003, 35% higher than $3.99 in the
fourth quarter of 2002. However, the Company received higher
electricity revenues in the 2003 quarter due to the reinstated
Standard Offer contracts effective January 2003, which resulted
in lower operating costs compared to the fourth quarter of 2002.
In addition to steam costs, the cost of supplies and equipment,
chemicals, utilities and insurance increased compared to the
first quarter of 2002. Operating costs per BOE of $9.31 in the
first quarter of 2003 were in line with the Company's 2003 target
of $8.50 to $9.50 per BOE.
To protect the cash flow from future increases in natural
gas prices on the fixed price contract on Unit 1 of the Company's
Placerita cogeneration facility, in April 2003, the Company
entered into natural gas swaps on a total volume of 5,000
MMBtu per day at a fixed price of $4.85 per MMBtu for the period
June 2003 through June 2006, thereby helping to control steam
costs.
DD&A for the first quarter of 2003 was $4.5 million, up 13%
from $4.0 million in the first quarter of 2002 and up 10% from
$4.1 million in the fourth quarter of 2002. The increase in the
first quarter of 2003 was primarily related to higher
depreciation rates for assets using the units of production
method due to higher production levels and depreciation on
additions from recent capital budget programs. On a per BOE
basis, DD&A was $3.15 in the first quarter of 2003, down from
$3.21 in the first quarter of 2002, but up from $2.90 in the
fourth quarter of 2002. Assuming stable natural gas and crude
oil prices, the Company currently anticipates that DD&A will
average between $3.15 and $3.25 per BOE during 2003.
G&A for the first quarter of 2003 was $2.3 million, or $1.59
per BOE, up 21% from $1.9 million, or $1.50 per BOE, in the first
quarter of 2002 and up 28% from $1.8 million, or $1.26 per BOE,
in the fourth quarter of 2002. The increase in the first quarter
of 2003 was due primarily to higher payroll, rent, insurance,
accounting fees and property evaluation costs related to the
Company's efforts to expand into a new core area outside of
California.
In 2002 and early 2003, the Company leased a total of
approximately 208,000 acres in Kansas and 54,000 acres in
Illinois for the purpose of exploring for economic concentrations
of coalbed methane gas for a total lease cost of approximately
$6.0 million. The Company drilled a five-well pilot on the
Illinois acreage in the fourth quarter of 2002 which, as
anticipated, continues to dewater. The results of this pilot are
not yet conclusive and are not expected to be known until the
latter half of 2003. The Company also drilled a five-well pilot
in the Wabaunsee County portion of the Kansas acreage late in the
fourth quarter of 2002. On this pilot, initial water production
was less than expected with no resulting gas pressure buildup and
the gas content of the coals was significantly lower than
anticipated. Consequently, the Company believes this pilot will
not produce commercial quantities of natural gas and, therefore,
wrote off the cost to drill the five-well pilot and the
associated leased acreage. The total amount charged to
operations in the first quarter of 2003 was $2.5 million. The
leased acreage in Kansas also includes positions in Jackson
County and Osage County. The Company is evaluating the location
and method of drilling additional test wells in these areas.
11
The Company experienced an effective tax rate of 22% for the
first quarter of 2003 compared to an effective tax rate of 11%
for the same period last year. The Company continues to invest
in qualifying enhanced oil recovery (EOR) projects. However, the
anticipated EOR credit in 2003 relative to higher pre-tax income
resulting from higher oil prices and increased production
resulted in a higher effective tax rate compared to the 2002
period. The Company anticipates an effective tax rate for 2003
below 25%, assuming WTI oil prices stabilize at approximately
$26/Bbl.
Liquidity and Capital Resources
Working capital at March 31, 2003 was $6.8 million, up from
$5.4 million at March 31, 2002 and up from a negative $3.7 million
at December 31, 2002. Net cash provided by operating activities
was $8.4 million in the first quarter of 2003, down from $16.5
million in the first quarter of 2002 and down from $15.9 million
in the fourth quarter of 2002. The decline from the first quarter
of 2002 was due to $3.0 million in capital costs incurred in 2002
but paid in 2003, approximately $1.6 million in additional annual
price-based royalty costs on one of the Company's properties and
$4.2 million in receivables and other revenue related to
electricity sales earned early in 2001 and recovered by the
Company in the first quarter of 2002. The payment of the price-
based royalty and higher cash outlays related to capital
expenditures in the first quarter of 2003 also accounts for the
decline in cash flow from operating activities from the fourth
quarter of 2002. Uses of funds in the first quarter of 2003
included the payment of the annual price-based royalty of $5.5
million, a total of $4.9 million for capital expenditures and
property acquisitions and the payment of $2.2 million in
dividends.
On April 8, 2003, the Company's Board of Directors approved
a special one-time dividend of $.04 per share, payable May 2,
2003, and a 10% increase in future dividends from $.10 to $.11
per share per quarter.
In the fourth quarter of 2002, the Company's Board of
Directors approved the capital budget for 2003 of $27.6 million,
which includes the drilling of 98 new wells, of which 13 are
horizontal, and 49 well workovers. As of March 31, 2003 five new
wells have been drilled, three of which were horizontal. The
Company is currently achieving its production targets for 2003
and, assuming stable natural gas and crude oil prices, believes
that the implementation of this year's budget will allow the
Company to meet its target exit production rate of approximately
17,700 BOE/day.
In the first quarter of 2003, the Company completed the
acquisition of a Poso Creek area property in Kern County,
California for $2.5 million, which was funded from cash flow from
operations. Management estimates that this property includes
approximately 2.5 million barrels of proved reserves. In April
2003, the Company entered into a Purchase and Sale Agreement for
the acquisition of producing properties and leasehold acreage in
the Brundage Canyon field in the Uinta Basin in Utah for
approximately $49 million, which is expected to close in the
third quarter of 2003. Management estimates the proved reserves
for Brundage Canyon at 8.6 million BOE (75% light oil and 25%
natural gas).
In 2003, the Company plans to spend approximately $1 million
for improvements at its Poso Creek property and may spend up to
$15.5 million in Utah to drill up to 26 development, step-out and
exploitation wells if that acquisition is closed early enough in
2003. These expenditures will be in
12
addition to the $27.6 million capital budget. The Company
anticipates funding the Brundage Canyon property acquisition
and related capital projects from cash generated from operations
and borrowings from its credit facility. The Company's current
target production rates and cost data do not include the effects
of these acquisitions.
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.
13
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company has significant market risk exposure related to
the prices received for the sale of its crude oil. A $1 change
in oil price per barrel equates to an approximate $5.8 million
change in annual revenues. The Company primarily uses zero-cost
bracketed collars based on WTI crude oil prices to protect cash
flow from a severe crude oil price decline. At March 31, 2003,
the Company has hedged 6,500 barrels per day for the remainder of
2003 whereby the Company could capture an average of $3.88 below
a WTI price of $22.31 per barrel and may give up to an average of
$4.48 above $25.79 per barrel. The Company has also hedged 5,000
barrels per day in the first quarter of 2004 and 4,000 barrels
per day for the second through fourth quarters of 2004. In 2004,
the Company could capture up to an average of $3.64 per barrel
below approximately $22.39 per barrel and may give up to an
average of $4.24 per barrel above $25.65 per barrel. In
addition to these collars, the Company entered into a series of
crude oil swaps based on WTI pricing on 1,500 barrels per day at
prices ranging from $25.68 to $27.17 covering the six month
period from May 1, 2003 to October 31, 2003 and 1,000 barrels per
day for the six months beginning November 2003 for an average
price of $25.00. The Company utilizes more than one counterparty
on these hedges and monitors each counterparty's credit rating.
The Company is also at risk for a widening of the
differential between the WTI crude oil price and the posted price
of the Company's heavy crude oil. To minimize this risk, the
Company has a sales contract in place through 2005 where more
than 90% of its crude oil production is priced at the higher of
local field posting plus a bonus, or WTI minus a fixed
differential.
The Company also has market risk exposure related to the
price received for the sale of its electricity production and the
cost paid by the Company for the natural gas used in its
cogeneration operations. The Company's three cogeneration
facilities, when combined, have electricity production capacity
of 98 Mw of electricity. Of this total, the Company sells
approximately 92 Mw and the remaining 6 Mw is consumed in the
Company's operations. The Company's goal is to control its
"spark spread" (the difference between the sales price received
for its electricity and the cost to purchase natural gas used as
fuel in the cogeneration operations).
The Company consumes approximately 27,000 MMBtu/day of
natural gas as fuel in these facilities. A change of $.25/MMBtu
in the cost of natural gas used in the cogeneration facilities
equates to a change of approximately $1.1 million in annual
operating costs. To protect cash flow from future increases in
natural gas prices, thereby helping to reduce steam costs, the
Company entered into natural gas swaps on a total volume of
5,000 MMBtu per day at a fixed price of $4.85 per MMBtu for the
period June 2003 through June 2006. The Company has a long-term
electricity sales contract in place, with a major utility,
through July 31, 2006 at a fixed price of $53.70/Mwh plus
capacity on approximately 19 Mw of electricity production. A
change of $1.50/Mwh in the price received for electricity on the
remaining 73 Mw equates to approximately $1 million in annual
revenues. During 2002, the majority of the remaining electricity
was sold on the open market to a creditworthy customer. To
protect a portion of the Company's electrical production from low
off-peak power prices, the Company entered into a series of fixed
price (swap) agreements on 30 Mw of off-peak hour electricity in
14
August 2002. At March 31, 2003, the Company has two months
remaining on the swap agreements in place through May 31, 2003 at
$21.00 per Mwh. In January 2003, the Company entered into three
reformed or reinstated Standard Offer contracts with the
utilities which resulted in improved electrical pricing in the
first quarter of 2003 and should also result in improved
electrical pricing for the remainder of 2003. These contracts
will expire no later than December 31, 2003. The Company is
pursuing longer-term arrangements on the sale of electricity and
may enter into hedges on its natural gas purchases to seek to
improve the spark spread in 2003 and beyond.
The Company also consumes up to an additional 10,000
MMBtu/day of additional natural gas as fuel in its conventional
generators, which are used to supplement the Company's steam
requirements. A change of $.25 in the cost of this natural gas
requirement equates to a change of approximately $.9 million in
annual operating costs. The Company may enter into hedges on
natural gas purchases to help control this cost or shut-in the
conventional generators if deemed appropriate.
Related to its natural gas purchases, the Company is also
exposed to the volatility in the differential between gas prices
at the Southern California border and Henry Hub delivery points.
To help minimize this risk, the Company entered into a 12,000
MMBtu/day firm transportation agreement on the Kern River
pipeline expansion for gas deliveries which commenced in
May 2003. This agreement provides the Company additional
flexibility in securing its natural gas supply and allows the
Company to potentially benefit from discounted natural gas prices
in the Rockies. This is a 10 year take-or-pay contract and the
Company is required to pay approximately $.71/MMBtu if the Company
does not take delivery of gas volumes under the agreement. This
10-year take-or-pay commitment totals approximately $31 million
over the life of the contract and for 2003 is approximately $2.1
million.
Item 4. Controls and Procedures
The Company's Chief Executive Officer and its Chief
Financial Officer have evaluated the Company's disclosure
controls and procedures within 90 days of the filing of this
report pursuant to Rule 13a-14 of the Securities and Exchange Act
of 1934 and have concluded that there are no significant changes
in the Company's internal controls or in other factors that could
significantly affect these controls.
15
BERRY PETROLEUM COMPANY
Part II. Other Information
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
On April 8, 2003, the Company filed a Form 8-K reporting an
Item 5 - Other Event to furnish the Securities and Exchange
Commission a copy of the Company's press release announcing a
dividend increase.
On April 24, 2003, the Company filed a Form 8-K reporting an
Item 5 - Other Event to furnish the Securities and Exchange
Commission a copy of the Company's press release announcing the
Company's intent to acquire certain Uinta Basin properties in
Utah.
(a) See Exhibit Index.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
BERRY PETROLEUM COMPANY
/s/ Donald A. Dale
Donald A. Dale
Controller
(Principal Accounting Officer)
Date: May 8, 2003
16
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
I, Jerry V. Hoffman, Chairman, President and Chief Executive
Officer of Berry Petroleum Company, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Berry
Petroleum Company;
2. Based on my knowledge, this quarterly report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant is made
known to us by others within the registrant, particularly during
the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: May 8, 2003 /s/ Jerry V. Hoffman
Jerry V. Hoffman
Chairman, President and
Chief Executive Officer
17
CERTIFICATION OF CHIEF FINANCIAL OFFICER
I, Ralph J. Goehring, Senior Vice President and Chief Financial
Officer of Berry Petroleum Company, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Berry
Petroleum Company;
2. Based on my knowledge, this quarterly report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant is made
known to us by others within the registrant, particularly during
the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: May 8, 2003 /s/ Ralph J. Goehring
Ralph J. Goehring
Senior Vice President and
Chief Financial Officer
18
EXHIBIT INDEX
Exhibit No.
99.1 Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
19