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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 June 30, 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 June 30, 2003, was 20,872,964 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
June 30, 2003
INDEX
Page No.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Balance Sheets at June 30, 2003 and
December 31, 2002 3
Condensed Income Statements for the Three Month Periods
Ended June 30, 2003 and 2002 4
Condensed Income Statements for the Six Month Periods
Ended June 30, 2003 and 2002 5
Condensed Statements of Comprehensive Income for the
Six Month Periods Ended June 30, 2003 and 2002 5
Condensed Statements of Cash Flows for the
Six Month Periods Ended June 30, 2003 and 2002 6
Notes to Condensed Financial Statements 7
Item 2. Management's Discussion and Analysis
Of Financial Condition and Results of Operations 10
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 15
PART II. OTHER INFORMATION
Item 4. Controls and Procedures 16
Item 5. Submission of Matters to a Vote of Security 17
Holders
EXHIBIT INDEX
Item 6. Exhibits and Reports on Form 8-K 17
SIGNATURES 18
EX-31.1 Rule 13a-14(a) Certification of CEO 19
EX-31.2 Rule 13a-14(a) Certification of CFO 20
EX-32.1 Section 1350 Certification of CEO 21
EX-32.2 Section 1350 Certification of CFO 22
2
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets
(In Thousands, Except Share Information)
June 30, December
2003 31, 2002
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 6,928 $ 9,866
Short-term investments available for sale 661 660
Accounts receivable 18,408 15,582
Prepaid expenses and other 3,922 2,597
-------- --------
Total current assets 29,919 28,705
Oil and gas properties (successful efforts
basis), buildings and equipment, net 237,137 228,475
Other assets 955 893
-------- --------
$ 268,011 $ 258,073
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 20,034 $ 19,189
Accrued liabilities 3,140 6,470
Federal and state income taxes payable 3,447 2,612
Fair value of derivatives 4,561 4,123
-------- --------
Total current liabilities 31,182 32,394
Long-term liabilities:
Deferred income taxes 34,317 33,866
Long-term debt 15,000 15,000
Abandonment obligation 5,113 4,596
Fair value of derivatives 522 159
-------- --------
Total long-term liabilities 54,952 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; 20,872,964 shares issued
and
outstanding at June 30, 2003 209 209
(20,852,695
at December 31, 2002)
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 49,105 49,052
Accumulated other comprehensive loss (3,050) (2,569)
Retained earnings 135,604 125,357
-------- --------
Total shareholders' equity 181,877 172,058
-------- --------
$ 268,011 $ 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 June 30, 2003 and 2002
(In Thousands, Except Per Share Information)
(Unaudited)
2003 2002
Revenues:
Sales of oil and gas $ 29,466 $ 25,568
Sales of electricity 10,386 6,477
Interest and other income, net 228 1,167
-------- --------
40,080 33,212
-------- --------
Expenses:
Operating costs - oil and gas production 15,626 10,893
Operating costs - electricity generation 10,386 6,477
Depreciation, depletion and amortization 4,729 4,278
General and administrative 2,404 2,032
Interest 268 261
-------- --------
33,413 23,941
-------- --------
Income before income taxes 6,667 9,271
Provision for income taxes 157 2,444
-------- --------
Net income $ 6,510 $ 6,827
======== ========
Basic net income per share $ .30 $ .31
======== ========
Diluted net income per share $ .30 $ .31
======== ========
Cash dividends per share $ .15 $ .10
======== ========
Weighted average number of shares
of capital stock outstanding (used to
calculate basic net income per share) 21,764 21,735
Effect of dilutive securities:
Stock options 145 198
Other 45 41
-------- --------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 21,954 21,974
======== ========
The accompanying notes are an integral part of these financial
statements.
4
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Income Statements
Six Month Periods Ended June 30, 2003 and 2002
(In Thousands, Except Per Share Information)
(Unaudited)
2003 2002
Revenues:
Sales of oil and gas $ 63,820 $ 45,246
Sales of electricity 23,265 13,791
Interest and other income, net 248 1,545
-------- --------
87,333 60,582
Expenses: -------- --------
Operating costs - oil and gas production 28,810 18,979
Operating costs - electricity generation 23,265 13,460
Depreciation, depletion and amortization 9,183 8,270
General and administrative 4,661 3,894
Recovery of electricity receivables - (3,631)
Dry hole and abandonment 2,487 -
Interest 477 684
-------- --------
68,883 41,656
-------- --------
Income before income taxes 18,450 18,926
Provision for income taxes 2,763 3,479
-------- --------
Net income $ 15,687 $ 15,447
======== ========
Basic net income per share $ .72 $ .71
======== ========
Diluted net income per share $ .72 $ .70
======== ========
Cash dividends per share $ .25 $ .20
======== ========
Weighted average number of shares
of capital stock outstanding (used to
calculate basic net income per share) 21,761 21,734
Effect of dilutive securities:
Stock options 130 140
Other 43 41
-------- --------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 21,934 21,915
======== ========
Condensed Statements of Comprehensive Income
Six Month Periods Ended June 30, 2003 and 2002
(in Thousands)
(Unaudited)
2003 2002
Net income $ 15,687 $ 15,447
Unrealized losses on derivatives, (net of
income taxes of $320 and $1,084,
respectively)
(481) (1,626)
-------- --------
Comprehensive income $ 15,206 $ 13,821
======== ========
The accompanying notes are an integral part of these financial
statements.
5
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Statements of Cash Flows
Six Month Periods Ended June 30, 2003 and 2002
(In Thousands)
(Unaudited)
2003 2002
Cash flows from operating activities:
Net income $ 15,687 $ 15,447
Depreciation, depletion and amortization 9,183 8,270
Dry hole and abandonment 2,432 (224)
Deferred income tax liability 451 1,140
Other, net 277 161
-------- --------
Net working capital provided by
operating activities 28,030 24,794
Decrease (increase) in accounts
receivable, prepaid expenses and other (3,975) 4,000
Decrease in current liabilities (1,650) (3,422)
-------- --------
Net cash provided by operating activities 22,405 25,372
Cash flows from investing activities:
Capital expenditures (12,636) (11,738)
Property acquisitions (7,447) -
Other, net 181 (44)
-------- --------
Net cash used in investing activities (19,902) (11,782)
Cash flows from financing activities:
Payment of long-term debt - (10,000)
Dividends paid (5,441) (4,347)
Other, net - (172)
-------- --------
Net cash used in financing activities (5,441) (14,519)
-------- --------
Decrease in cash and cash equivalents (2,938) (929)
Cash and cash equivalents at beginning of
year 9,866 7,238
-------- --------
Cash and cash equivalents at end of period $ 6,928 $ 6,309
======== ========
Supplemental non-cash activity:
Decrease in fair value of derivatives:
Current (net of income taxes of $175 and
$1,084 in 2003 and 2002, respectively) $ 263 $ 1,626
Non-current (net of income taxes of $145
and $0 in 2003 and 2002, respectively) 218 -
Net decrease to accumulated other -------- --------
comprehensive income $ 481 $ 1,626
======== ========
The accompanying notes are an integral part of these financial
statements.
6
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
June 30, 2003
(Unaudited)
1. All adjustments which are, in the opinion of management,
necessary for a fair presentation of the Company's financial
position at June 30, 2003 and December 31, 2002 and results of
operations for the three and six month periods ended June 30,
2003 and 2002 and cash flows for the six month periods ended June
30, 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 and the March 31, 2003 Form 10-Q
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
Wabaunsee, Jackson and Osage counties in Kansas and 55,000 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, in the first quarter of 2003,
the Company wrote off the cost to drill the five-well pilot and
the associated leased acreage for a total charge of $2.5 million.
The Company is still evaluating the location and method of
drilling test wells in Osage County which the Company anticipates
drilling towards the end of 2003. The Company entered into a
definitive agreement in July 2003 to sell its approximately
43,000 acreage position in Jackson County, for an undisclosed
amount which covers the Company's cost in this acreage, while
retaining an overriding royalty interest in the property. The
transaction is subject to certain conditions and, if all
conditions are satisfied, the Company anticipates the sale to
close in the third quarter of 2003.
4. 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 related interpretations in recording compensation
related to its plan.
7
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
4. (cont'd) 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 the method of
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 and six months
ended June 30, 2003 and 2002 (in thousands, except per share
data):
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
Compensation cost, net of income
taxes
As reported $ 35 $ 21 $ 55 $ 26
Pro forma 164 201 315 362
Net income:
As reported 6,510 6,827 15,687 15,447
Pro forma 6,381 6,647 15,427 15,111
Basic net income per share:
As reported .30 .31 .72 .71
Pro forma .29 .31 .71 .70
Diluted net income per share:
As reported .30 .31 .72 .70
Pro forma .29 .30 .71 .69
5. In April 2003, the Company entered into a purchase and sale
agreement with Williams Production RMT Company to acquire its oil
and gas properties located in Brundage Canyon, Utah in the Uinta
Basin for approximately $48.6 million. The properties, located
in northeastern Utah, consist of approximately 43,500 net acres,
and are currently producing approximately 2,000 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) as of April 1, 2003. The Company paid a deposit of $4.9
million in May (recorded in oil and gas properties) from cash
generated from operations and anticipates funding the remainder
from borrowings on its credit facility. The closing is expected
to occur in the third quarter of 2003, although, the completion
of the transaction is subject to certain conditions and there is
no assurance that all conditions will be satisfied.
8
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
6. The Company successfully completed a new $200 million
unsecured three year bank credit facility in July. Participants
included several large banks based in the United States as well
as international banking institutions. The facility replaces the
previous $150 million facility which was due to mature in January
2004. The new facility recognizes the Company's strong financial
position and should provide significant low-cost capital for the
Company to grow, primarily through acquisitions. Initial
borrowings were $15 million which represented an amount equal to
the borrowings outstanding under the previous credit facility.
7. In April 2003, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging
Activities." This statement is effective for contracts entered
into or modified after June 30, 2003 and is also effective for
hedging relationships designated after June 30, 2003.
Implementation of this standard is not expected to have a
material impact on the Company's financial position or results of
operations.
9
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 $6.5 million, or $.30 per
share, on revenues of $40.1 million in the second quarter of
2003, down 4% from net income of $6.8 million, or $.31 per share,
on revenues of $33.2 million in the second quarter of 2002, and
down 29% from net income of $9.2 million, or $.42 per share, on
revenues of $47.3 million in the first quarter of 2003. Net
income for the six months ended June 30, 2003 was $15.7 million,
or $.72 per share, on revenues of $87.3 million, up 2% from $15.4
million, or $.71 per share, on revenues of $60.6 million for the
six months ended June 30, 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 six months of 2002
include a pre-tax gain from the recovery of a $3.6 million
receivable for electricity sales which was written off in 2001.
Three Months Ended Six Months Ended
June March June June June
30, 31, 30, 30, 30,
2003 2003 2002 2003 2002
Oil and gas:
Net Production - BOE per day 15,397 15,736 14,060 15,566 13,930
day
Per BOE:
Realized sales price(1) $21.07 $24.23 $19.99 $22.66 $17.96
Operating costs (2) 10.63 8.78 7.96 9.71 6.98
Production taxes .52 .53 .55 .52 .55
----- ----- ----- ----- -----
Total operating costs 11.15 9.31 8.51 10.23 7.53
Depreciation/Depletion (DD&A) 3.38 3.15 3.34 3.26 3.28
General & administrative
expenses (G&A) 1.72 1.59 1.59 1.65 1.54
Interest expense .19 .15 .20 .17 .27
Electricity:
Production - Mwh per day 2,036 2,137 1,935 2,086 1,992
Sales - Mwh per day 1,847 1,951 1,748 1,899 1,819
Average sales price - $/Mwh 62.59 73.39 39.46 68.11 36.79
Fuel gas cost - $/Mmbtu 5.04 5.40 2.97 5.21 2.73
(1) Includes realized hedge losses of $1.42, $2.62 and $.51 for the three
months ended June 30, 2003, March 31, 2003 and June 30, 2002,
respectively, and losses of $2.02 and $.26 for the six months ended June
30, 2003 and 2002, respectively.
(2) Includes monthly expenses in excess of monthly revenues from
cogeneration operations of $2.79, $1.72 and $1.73 for the second quarter
of 2003, the first quarter of 2003 and the second quarter of 2002,
respectively. For the first six months of 2003 and 2002, respectively,
these expenses represent $2.25 and $1.03.
Operating income from oil and gas operations for the second
quarter of 2003 was $9.2 million, down from $14.3 million and
$10.5 million in the first quarter of 2003 and the second quarter
of 2002, respectively. Operating income from oil
10
and gas operations for the first six months of 2003 was $23.5 million,
up from $18.2 million for the first six months of 2002.
Oil and gas production (BOE/day) was 15,397 in the second
quarter of 2003, up 10% from 14,060 in the second quarter of
2002, but down 2% from 15,736 in the first quarter of 2003. A
significant portion of the Company's 2003 drilling program was
completed during the second quarter. As of July 15, 2003, the
Company has drilled and completed 46 (including 13 horizontal
wells) of the 99 new wells originally budgeted to be drilled in
2003. Because of the close proximity between wells, a number of
existing wells had to be shut-in temporarily while certain of the
new wells were drilled in the second quarter which contributed to
the decline in production from the first quarter. However, the
majority of these wells are now back on production. The Company
is making a concerted effort to increase production during 2003.
During the second quarter, the Company increased its steam
injection volumes to an average of over 64,000 B/D and plans to
average between 68,000 and 70,000 B/D for the remainder of the
year, assuming stable crude oil and natural gas prices. Crude
oil production has averaged 15,600 BOE/day for the first half of
2003 and is averaging approximately 16,000 BOE/day as of July 31,
2003. With the 2003 development program and the increased
steaming activity, the Company anticipates production to average
approximately 16,000 BOE/day from its existing properties for all
of 2003 which would represent a 14% increase over 2002
production. In addition, we still expect to close our Brundage
Canyon acquisition in the third quarter of 2003. If that closing
should occur, the Company's production would increase by Brundage
Canyon's current production of approximately 2,000 BOE/day.
The average price received for the Company's heavy crude oil
in the second quarter of 2003 was $21.07 per barrel, up 5% from
$19.99 received in the second quarter of 2002, but down 13% from
$24.23 received in the first quarter of 2003. This price decline
resulted in a $4.4 million reduction in revenues from sales of
oil and gas in the second quarter of 2003 compared to the first
quarter of 2003. The posted price for the Company's crude oil
has rebounded to $26.50 per barrel as of August 4, 2003 which is
15% higher than the average posted price of $23.07 for the second
quarter of 2003.
The Company primarily is at risk to sharp reductions in
operating income as a result of declines in crude oil and
electricity prices and increases in natural gas prices. To
mitigate these risks, the Company periodically enters into
various types of commodity hedges. See "Item 3. Quantitative and
Qualitative Disclosure About Market Risk" for detail of market
risk and existing hedges for the Company at June 30, 2003.
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 $58.89 per Mwh in the second
quarter of 2003 and $65.13 for the first six months 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 help to 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.
11
Operating costs from oil and gas operations in the second
quarter were $15.6 million, or $11.15 per BOE, up from $13.2
million, or $9.31 per BOE, in the first quarter of 2003 and $10.9
million, or $8.51 per BOE, in the second quarter of 2002. The
two major components of operating costs are costs associated with
steam generation and non-steam related costs.
Non-steam operating costs, the component which is the more
controllable factor, has been effectively managed by the Company.
Total non-steam operating costs for the second quarter of 2003
were $6.5 million, or $4.66 per BOE, compared to $6.0 million, or
$4.69 per BOE, in the second quarter of 2002 and $6.2 million, or
$4.37 per BOE, in the first quarter of 2003.
Steam costs, however, increased substantially in the second
quarter of 2003 due to high natural gas prices, lower electricity
revenue, scheduled turnarounds at the Company's cogeneration
facilities and higher steam injection volumes from the Company's
higher cost conventional sources. The price per MMBtu the
Company paid for natural gas was $5.04 in the second quarter of
2003, compared to $5.40 in the first quarter of 2003 but up 70%
from $2.97 in the second quarter of 2002. The Company's
electricity revenue is based on the price of natural gas at the
Northern California border (Malin), however, the majority of the
Company's gas purchases is based on the price of gas at the
Southern California border (SoCal). In the first quarter of
2003, the price of Malin gas was an average of $.15 per MMBtu
higher than the price at SoCal resulting in high electricity
prices relative to the Company's cost of fuel. In the second
quarter of 2003, the cost of gas at Malin was an average of $.30
per MMBtu lower than the cost of gas at SoCal resulting in
relatively low electricity prices and lower electricity revenues.
Lower natural gas prices in the second quarter and, to a lesser
extent, this $.45 per MMBtu swing were the principal reasons why
electricity revenues declined $2.5 million, or 19%, in the second
quarter of 2003 compared to the first quarter of 2003. Also
contributing to higher steam costs in the second quarter were
increased steam volumes from conventional generators. Injection
from these sources averaged 26,973 B/D, up 15% and 26% from
23,539 B/D in the second quarter of 2002 and 21,363 B/D in the
first quarter of 2003, respectively.
To protect the Company's cash flow from future increases in
natural gas prices on the fixed electricity price contract on
Unit 1 of the Company's Placerita cogeneration facility, 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. The Company also entered into a 1,000 MMBtu per day swap
at a fixed price of $4.55 for November 2003 through March 2004.
DD&A for the second quarter of 2003 was $4.7 million, or
$3.38/BOE, up from $4.3 million, or $3.34/BOE, in the second
quarter of 2002 and $4.5 million, or $3.15/BOE, in the first
quarter of 2003, respectively. The Company anticipates that,
assuming stable crude oil and natural gas prices, the rate per
BOE will trend lower during the latter half of the year.
G&A for the second quarter of 2003 was $2.4 million, or
$1.72/BOE, up 20% from $2.0 million, or $1.59/BOE, in the second
quarter of 2002 and up 4% from $2.3 million, or $1.59/BOE, in the
first quarter of 2003. The increases in the 2003 periods
compared to the second quarter of 2002 were primarily related to
the Company's efforts to expand into a new core area outside of
California. To that end, the Company opened a Denver office in
February 2003 and incurred higher property evaluation costs in
the 2003 periods compared to the 2002 period. On a
12
per BOE basis, the Company anticipates G&A to trend lower in the
latter half of 2003 as production levels are expected to increase
through the remainder of the year.
The Company has leased approximately 208,000 acres in
Wabaunsee, Jackson and Osage counties, Kansas and 55,000 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, in the first quarter of 2003 the
Company wrote off the cost to drill the five-well pilot and the
associated leased acreage for a total charge of $2.5 million .
The Company is still evaluating the location and method of
drilling test wells in Osage County which the Company anticipates
drilling towards the end of 2003. The Company entered into a
definitive agreement in July 2003 to sell approximately 43,000
acres in Jackson County, for an undisclosed amount which covers
the Company's cost in this acreage, while retaining an overriding
royalty interest in the property. The transaction is subject to
certain conditions and, if all conditions are satisfied, the
Company anticipates the sale to close in the third quarter of
2003.
The Company's effective tax rate was 2% in the second
quarter of 2003, down from 22% in the first quarter of 2003 and
down from 26% in the second quarter of 2002. The primary reasons
for the significantly lower income taxes in the second quarter of
2003 versus the first quarter was significantly lower pre-tax
income (due to lower crude oil prices, higher operating costs and
lower production volumes) and anticipated higher EOR credits due
to higher natural gas prices which increased steam cost per BOE
used in the EOR calculation.
Liquidity and Capital Resources
Working capital at June 30, 2003 was ($1.3) million, up from
($3.7) million at December 31, 2002. Net cash provided by
operations was $22.4 million for the first six months of 2003,
down from $25.4 million for the first six months of 2002. Cash
was used in the first half of 2003 to pay dividends of $5.4
million, capital expenditures of $12.6 million, property
acquisitions of $7.4 million and to pay an annual revenue sharing
royalty on 2002 production of $5.5 million.
In April 2003, the Company entered into a purchase and sale
agreement with Williams Production RMT Company to acquire its oil
and gas properties located in Brundage Canyon, Utah in the Uinta
Basin for $48.6 million. The properties, located in northeastern
Utah, consist of approximately 43,500 net acres, and are
currently producing approximately 2,000 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) as of
April 1, 2003. The Company paid a deposit of $4.9 million
(recorded in oil and gas properties) in May from cash generated
from operations and anticipates funding the remainder from
borrowings on its credit facility. The closing is expected to
occur in the third quarter of 2003 although the completion of the
transaction is subject to certain conditions and there is no
assurance that all conditions will be satisfied.
13
During the second quarter of 2003, the Company aggressively
pursued the implementation of its 2003 capital development
budget. As of July 15, 2003, 46 wells, including all 13 of the
planned horizontal wells, have been drilled. For the remainder
of 2003, the Company plans to drill an additional 53 wells on its
existing properties and up to an additional 26 development wells
at Brundage Canyon in Utah, assuming the purchase closes in the
third quarter. The number of wells that may actually be drilled
at Brundage Canyon will depend on whether or not and when the
actual closing occurs. This planned activity would bring the
total estimated development (drilling and facility) spending for
2003 to approximately $44 million.
The Company successfully completed a new $200 million
unsecured three year bank credit facility in July 2003.
Participants included several large banks based in the United
States as well as international banking institutions. The
facility replaces the previous $150 million facility which was
due to mature in January 2004. The new facility recognizes the
Company's strong financial position and should provide
significant low-cost capital for the Company to grow, primarily
through acquisitions. Initial borrowings were $15 million which
represented an amount equal to the borrowings outstanding under
the previous credit facility.
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.
14
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 June 30, 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 mitigate this risk, the
Company has a sales contract in place through 2005 where more
than 90% of its crude oil production from its California
properties 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 and an additional gas swap on 1,000
MMBtu per day at a fixed price of $4.55 per MMBtu for the period
November 2003 through March 2004. 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
15
creditworthy customer. 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 half 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 additional 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.
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 use-or-pay contract at approximately
$.71/MMBtu and the Company is currently transporting volumes
under the terms of the agreement. This 10-year use-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.
16
BERRY PETROLEUM COMPANY
Part II. Other Information
Item 5. Submission of Matters to a Vote of Security Holders
At the annual meeting, which was held at the Stockdale Towers on
May 19, 2003, ten incumbent directors were re-elected. The results of
voting as reported by the inspector of elections are noted below:
1. There were 21,758,962 shares of the Company's common stock issued,
outstanding and entitled to vote as of the record date, March 12,
2003.
2. There were present at the meeting, in person or by proxy, the
holders of 19,177,252 shares, representing 88.13% of the total
number of shares outstanding and entitled to vote at the meeting,
such percentage representing a quorum.
PROPOSAL ONE: Election of Directors
PERCENT OF
NOMINEE QUORUM WITHHOLD
FOR VOTES VOTES CAST AUTHORITY
William F. Berry 18,952,361 98.83% 224,891
Ralph B. Busch, III 19,007,167 99.11% 170,085
William E. Bush, Jr. 19,006,312 99.11% 170,940
Stephen L. Cropper 19,006,945 99.11% 170,307
J. Herbert Gaul, Jr. 19,006,945 99.11% 170,307
John A. Hagg 19,006,725 99.11% 170,527
Robert F. Heinemann 16,574,232 86.43% 2,603,020
Jerry V. Hoffman 17,716,453 92.38% 1,460,799
Thomas J. Jamieson 18,988,648 99.02% 188,604
Martin H. Young, Jr. 19,006,945 99.11% 170,307
Percentages are based on the shares represented and voting at
the meeting in person or by proxy.
Item 6. Exhibits and Reports on Form 8-K
Exhibit No. Description
31.1 Rule 13a-14(a) Certification of Chief Executive Officer
31.2 Rule 13a-14(a) Certification of Chief Financial Officer
32.1 Rule 1350 Certification of Chief Executive Officer
32.2 Rule 1350 Certification of Chief Financial Officer
17
BERRY PETROLEUM COMPANY
Part II. Other Information
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K (cont'd)
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.
On May 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 the
first quarter results for 2003.
On July 15, 2003, 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 completion of a new $200 million unsecured
credit facility.
On July 22, 2003, 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 entering into a definitive agreement to sell its
interest in 43,000 acres of non-producing coal bed methane
acreage in eastern Kansas.
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: August 6, 2003
18