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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, 2002
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 93309-0645
(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 ( )
The number of shares of each of the registrant's classes of capital
stock outstanding as of June 30, 2002, was 20,844,095 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.
1
BERRY PETROLEUM COMPANY
JUNE 30, 2002
INDEX
PART I. Financial Information Page No.
Item 1. Financial Statements
Condensed Balance Sheets at
June 30, 2002 and December 31, 2001 3
Condensed Income Statements for the Three Month Periods
Ended June 30, 2002 and 2001 4
Condensed Income Statements for the Six Month Periods
Ended June 30, 2002 and 2001 5
Condensed Statements of
Comprehensive Income for the Six Month Periods
Ended June 30, 2002 and 2001 5
Condensed Statements of
Cash Flows for the Six Month Periods
Ended June 30, 2002 and 2001 6
Notes to Condensed Financial Statements 7
Item 2. Management's Discussion and Analysis
Of Financial Condition and Results of Operations 8
PART II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders 12
Item 6. Exhibits and Reports on Form 8-K 13
SIGNATURES 13
2
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets
(In Thousands, Except Share Information)
June 30, December 31,
2002 2001
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 6,309 $ 7,238
Short-term investments available for sale 659 594
Accounts receivable 13,607 17,577
Prepaid expenses and other 3,845 2,792
Total current assets 24,420 28,201
Oil and gas properties (successful efforts
basis), buildings and equipment, net 207,100 203,413
Other assets 823 912
$ 232,343 $ 232,526
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 10,052 $ 11,197
Fair value of derivatives 2,710 -
Federal and state income taxes payable 4,699 4,078
Accrued Liabilities and other 4,191 7,089
Total current liabilities 21,652 22,364
Long-term debt 15,000 25,000
Deferred income taxes 33,149 32,009
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; 20,844,095 shares issued and
outstanding at June 30, 2002 (20,833,094
at December 31, 2001) 208 208
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 48,820 48,905
Accumulated other comprehensive income (1,626) -
Retained earnings 115,131 104,031
Total shareholders' equity 162,542 153,153
$ 232,343 $ 232,526
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, 2002 and 2001
(In Thousands, Except Per Share Information)
(Unaudited)
2002 2001
Revenues:
Sales of oil and gas $ 25,568 $ 27,731
Sales of electricity 6,477 1,316
Interest and other income, net 1,167 357
33,212 29,404
Expenses:
Operating costs - oil and gas production 10,893 11,166
Operating costs - electricity generation 6,477 1,316
Depreciation, depletion and amortization 4,278 3,896
General and administrative 2,032 2,021
Interest 261 1,155
23,941 19,554
Income before income taxes 9,271 9,850
Provision for income taxes 2,444 2,875
Net income $ 6,827 $ 6,975
Basic net income per share $ .31 $ .32
Diluted net income per share $ .31 $ .32
Cash dividends per share $ .10 $ .10
Weighted average number of shares
of capital stock outstanding (used to
calculate basic net income per share) 21,735 22,034
Effect of dilutive securities:
Stock options 198 29
Other 41 21
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 21,974 22,084
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, 2002 and 2001
(In Thousands, Except Per Share Information)
(Unaudited)
2002 2001
Revenues:
Sales of oil and gas $ 45,246 $ 58,428
Sales of electricity 13,791 18,534
Interest and other income, net 1,545 979
60,582 77,941
Expenses:
Operating costs - oil and gas production 18,979 21,806
Operating costs - electricity generation 13,460 18,335
Depreciation, depletion and amortization 8,270 8,675
General and administrative 3,894 3,938
Write-off (recovery) of electricity
receivables (3,631) 6,645
Interest 684 2,312
41,656 61,711
Income before income taxes 18,926 16,230
Provision for income taxes 3,479 4,233
Net income $ 15,447 $ 11,997
Basic net income per share $ .71 $ .54
Diluted net income per share $ .70 $ .54
Cash dividends per share $ .20 $ .20
Weighted average number of shares
of capital stock outstanding (used to
calculate basic net income per share) 21,734 22,034
Effect of dilutive securities:
Stock options 140 36
Other 41 18
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 21,915 22,088
Condensed Statements of Comprehensive Income
Six Month Periods Ended June 30, 2002 and 2001
(in Thousands)
2002 2001
Net income $ 15,447 $ 11,997
Unrealized losses on derivatives (net of
income taxes of $1,084) (1,626) -
Reclassification of realized gain on
derivatives (net of income taxes of $294) - (441)
Comprehensive income $ 13,821 $ 11,556
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, 2002 and 2001
(In Thousands)
(Unaudited)
2002 2001
Cash flows from operating activities:
Net income $ 15,447 $ 11,997
Depreciation, depletion and amortization 8,270 8,674
Deferred income tax liability 1,140 1,210
Other comprehensive income (1,626) (441)
Other, net (64) (63)
Net working capital provided by
operating activities 23,167 21,377
Decrease (increase) in accounts
receivable,prepaid expenses and other 2,917 (4,125)
Decrease in current liabilities (712) (17,413)
Net cash provided by (used in)
operating activities 25,372 (161)
Cash flows from investing activities:
Capital expenditures (11,738) (4,302)
Property acquisitions - (2,149)
Purchase of short-term investments (659) -
Maturity of short-term investments 594 -
Other, net 21 (6)
Net cash used in investing activities (11,782) (6,457)
Cash flows from financing activities:
Proceeds from issuance of long-term debt - 45,000
Payment of long-term debt (10,000) (4,000)
Dividends paid (4,347) (4,407)
Other (172) -
Net cash provided by (used in)
financing activities (14,519) 36,593
Net (decrease) increase in cash and cash
equivalents (929) 29,975
Cash and cash equivalents at beginning of
year 7,238 2,731
Cash and cash equivalents at end of period $ 6,309 $ 32,706
The accompanying notes are an integral part of these financial statements.
6
BERRY PETROLEUM COMPANY
Part I. Financial Information
Notes to Condensed Financial Statements
June 30, 2002
(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, 2002
and December 31, 2001 and results of operations for the three and six
month periods ended June 30, 2002 and 2001 and cash flows for the six
month periods ended June 30, 2002 and 2001 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, 2001 financial statements. The December 31, 2001 Form
10-K and the March 31, 2002 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. In March 2002, the Company entered into a series of put and call crude
oil option contracts with two independent counterparties, effectively
creating a zero-cost collar on 5,000 barrels per day covering the period
April 1, 2002 through March 31, 2003. For the second quarter ended June
30, 2002, the Company recorded an after-tax net loss of approximately $.4
million related to those crude oil hedge contracts. Due to the change in
the fair value of the remaining barrels on the hedging instruments during
the quarter, the Company recorded an after-tax charge of $1.6 million to
"accumulated other comprehensive income" on the Company's balance sheet
with an offset to the caption "fair value of derivatives" in current
liabilities at June 30, 2002. In July 2002, two bracketed zero-cost
collars were executed for the period April 2003 through March 2004 which
hedges 5,000 barrels per day for an additional year.
4. In July 2002, the Company entered into a series of "swap transactions"
on 30 Mwh of offpeak power. The first of these agreements is effective
August 1, 2002 through September 2002 and, in conjunction with the
Company's existing open market electricity contracts, effectively
establishes a fixed price of $20/Mwh for the offpeak period each day
during the term of the contract. Additional transactions for the same
quantity of offpeak power were executed from October 1, 2002 through May
2003 at rates slightly above $20/Mwh. The Company also entered into
transactions for 25 Mwh of onpeak power for August and September. The
above agreements were executed to protect the Company from future low
power rates and are part of the Company's risk management program to
remove a portion of the price volatility risk from its operating margins.
7
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 $6.8 million, or $.31 per share, on
revenues of $33.2 million in the second quarter of 2002, down 3% from $7.0
million, or $.32 per share, on revenues of $29.4 million in the second
quarter of 2001. Net income for the six months ended June 30, 2002 was
$15.4 million, or $.71 per share, on revenues of $60.6 million, up 28%
from $12.0 million, or $.54 per share, on revenues of $77.9 million for
the same period in 2001. Net income in the second quarter of 2002
includes the sale of surplus emission credits to a major utility company
for $1.1 million, pre-tax. The year-to-date results for 2002 also include
the recovery of $3.6 million of electricity receivables which were
previously written off in the first quarter of 2001.
Three Months Ended Six Months Ended
June 30, March 31, June 30, June 30, June 30,
2002 2002 2001 2002 2001
Oil and gas:
Net Production - BOE per day 14,060 13,799 13,611 13,930 14,445
Per BOE:
Realized sales price(1) $19.99 $15.87 $21.14 $17.96 $21.83
Operating costs (2) 7.96 5.96 8.57 6.98 7.75
Production taxes .55 .56 .45 .55 .43
Total operating costs 8.51 6.52 9.02 7.53 8.18
Depreciation/Depletion (DD&A) 3.34 3.21 3.15 3.28 3.32
General & administrative
expenses (G&A) 1.59 1.50 1.63 1.54 1.51
Interest expense .20 .34 .93 .27 .88
Electricity:
Production - Mwh per day 1,935 2,051 268 1,992 712
Sales - Mwh per day 1,748 1,890 224 1,819 654
Average sales price - $/Mwh 39.46 42.99 62.17 36.79 79.14
Fuel gas cost - $/Mmbtu 2.97 2.49 10.54 2.73 14.00
(1) Includes realized hedge losses of $.51 and $.26 for the three and six
months ended June 30, 2002, respectively. Excludes unrealized hedging
gains of $.91 and $.42 for the three and six months ended June 30, 2001,
respectively.
(2) Includes monthly expenses in excess of monthly revenues from
cogeneration operations of $1.73, $.31 and $2.32 for the second quarter of
2002, the first quarter of 2002 and the second quarter of 2001,
respectively. For the first six months of 2002 and 2001, respectively,
these expenses represent $1.03 and $1.64.
Operating income from oil and gas operations for the three and six
months ended June 30, 2002 was $10.5 million and $18.2 million,
respectively, down 18% and 35% from $12.8 million earned in the second
quarter of 2001 and $28.1 million earned in the first six months of 2001,
respectively.
8
The largest contributor to the decline in operating income in the
second quarter of 2002 from the second quarter of 2001 was a $2.2 million
decline in oil and gas sales which occurred for two reasons; first, the
average realized sales price/BOE declined 5% to $19.99 in the 2002 three
month period from $21.14 in the same 2001 quarter, and second, the Company
recorded an unrealized hedging gain of $1.1 million in the second quarter
of 2001 compared to a $.7 million realized loss in 2002. Similarly,
operating income declined for the six months ended June 30, 2002 from the
first six months of 2001 due to an 18% decline in the average realized
sales price per BOE to $17.96 in the 2002 period and because of the
unrealized hedging gain recorded in June 2001.
Oil and gas production (BOE per day) in the second quarter was 14,060,
up from 13,611 in the second quarter of 2001 and 13,799 in the first
quarter of 2002. However, production has averaged 13,930 for the first six
months of 2002, down from 14,445 for the six months ended June 30, 2001.
The Company has not as yet been able to attain the production levels
experienced before the suspension of steaming in 2001 due to the California
energy crisis. Currently, steam injection is approximately 65,000 barrels
per day and management believes that the new wells drilled and the existing
well workovers completed under the 2002 capital development program,
combined with the application of cyclic and sequential steaming techniques,
will improve production rates and the Company expects to exit 2002 with a
production level of approximately 16,000 BOE per day.
Due to an increase in steam costs resulting from higher steam
injection volumes, higher natural gas prices and lower electricity prices,
the Company experienced an increase in operating cost/BOE to $8.51 in the
second quarter of 2002 from $6.52 in the first quarter of 2002. Until June
2002, the Company sold approximately 37 Mwh of electricity under fixed rate
contracts and 43 Mwh in the open market. Effective June 2002, one fixed
rate contract expired and, therefore, an additional approximate 17 Mwh is
now sold in the open market with 20 Mwh remaining under a long-term fixed
rate contract. The average price received for electricity sales in the
open market for the three and six months ended June 30, 2002 was $22.59/Mwh
and $22.57/Mwh, respectively, while the cost of natural gas to run the
cogeneration plants during these same three and six month periods averaged
$2.73/Mmbtu and $2.97/Mmbtu, respectively. This combination resulted in a
weak "spark spread" (the difference between the price realized from the
sale of electricity and the cost paid for natural gas used as fuel in the
cogeneration operations) in the second quarter of 2002. The loss/BOE from
the cogeneration operations reflected in the Company's steam costs
increased to $1.73 in the second quarter of 2002 from $.31 in the first
quarter of 2002. The electrical marketplace in California continues to be
unpredictable due in part to the State of California's significant power
purchase commitments (with possible excess power at times), continued
rulemaking and a very limited open market for creditworthy buyers and
sellers. The Company continues to seek a long-term agreement for the sale
at reasonable prices of the approximately 60 Mwh presently sold on the open
market, but until that occurs, the Company may utilize more financial
hedges to reduce the volatility of the resulting steam costs.
DD&A was $4.3 million, or $3.34/BOE, in the second quarter, up from
$3.9 million, or $3.15/BOE, in the second quarter of 2001 and $4.0 million,
or $3.21/BOE, in the first quarter of 2002. The increase from the second
quarter of 2001 was due primarily to capital development projects completed
in the latter half of 2001 and the first half of 2002. The Company
anticipates that its DD&A per BOE will fluctuate between $3.00 and $3.50
over the next several quarters.
9
G&A of $2.0 million for the second quarter of 2002 was equivalent to
the second quarter of 2001 and up slightly from $1.9 million in the first
quarter of 2002. Lower legal costs in the second quarter of 2002 compared
to the second quarter of 2001 were offset primarily by higher costs for
consulting, property evaluations and office rent.
The Company experienced an effective tax rate of 26% in the second
quarter and 18% for the first six months of 2002 compared to 29% and 26% in
the same 2001 periods, respectively. The higher effective rate in the
second quarter of 2002 compared to the rate for the first three months of
2002 of 11% was due primarily to the increase in oil prices and production.
The Company anticipates that its effective tax rate will remain well below
the combined federal and state statutory rate due to the Company's
significant investment in numerous enhanced oil recovery projects in 2002.
As part of the Company's risk management program, the Company's goal
is to protect itself from large swings in commodity prices, i.e., sharp
declines in crude oil and electricity realized sales prices and the cost of
purchased natural gas used in its operations. The Company has entered into
certain hedge transactions during 2002 to reduce the volatility of its cash
flows related to these commodity prices.
In March 2002, the Company entered into a series of put and call
option contracts with two counterparties, effectively creating a zero-cost
collar on 5,000 barrels per day, representing approximately 35% of the
Company's current total oil production. Both hedges were effective April
1, 2002 for a period of one year. The Company's goal when entering into
these types of arrangements is to protect its operations from sharp
declines in oil prices while giving up only a portion of potential
increases in realized oil prices. In July 2002, two bracketed zero-cost
collars were executed for the period April 2003 through March 2004 which
hedges 5,000 barrels per day for an additional year. Since the sales price
received by the Company for the sale of its crude oil was slightly higher
than the top end of the collar during the second quarter of 2002, the
Company incurred after-tax hedging losses of approximately $.4 million in
the second quarter related to these hedge contracts and recorded an after-
tax charge to "accumulated other comprehensive income" of $1.6 million with
an offset to the caption "fair value of derivatives" in current liabilities
at June 30, 2002.
In January 2002, the Company entered into an energy conversion
arrangement with an electricity customer for February, March, May and June
2002. Under the terms of the agreement, the Company sold approximately 25
Mwh of electricity to a customer in exchange for a sufficient volume of gas
to produce this electricity and the Company's payment of an additional fee.
This arrangement minimized the Company's risk to fluctuating natural gas
and electricity prices related to these volumes and provided steam at a
cost less than $1/Bbl to the Company's heavy oil producing operations.
In July 2002, the Company entered into a series of swap transactions
which established a fixed price mechanism for 30 Mwh of offpeak electricity
averaging slightly higher than $20.00/Mwh from August 2002 through May
2003. The Company also entered into transactions for 25 Mwh of onpeak
power for August and September. The Company may enter into additional
commodity hedging transactions if management believes it is prudent to do
so. The Company is aware of counterparty risk and anticipates entering
into such hedges only with well established and well financed
counterparties. However, the Company can make no assurances as to the
ultimate financial performance of any of its counterparties.
10
Liquidity and Capital Resources
Working capital at June 30, 2002 was $2.8 million, down from $50.4
million at June 30, 2001, and $5.4 million at March 31, 2002. Working
capital was maintained at an unusually high level in the second quarter of
2001 to deal effectively with the financial consequences of the California
energy crisis. Net cash provided by operations was $25.4 million for the
first six months of 2002, up substantially from a $.2 million use of funds
for the first six months of 2001. Cash flow from operations was negatively
affected by the non-payment of $26.6 million in electricity sales from two
major California utilities in the first quarter of 2001. The Company
subsequently collected approximately $23.8 million of these sales. Cash
was used in the first half of 2002 to reduce long-term debt by $10.0
million and pay capital expenditures of $11.7 million, dividends of $4.3
million and an annual revenue sharing royalty on 2001 production of $3.9
million.
The Company's capital budget for 2002 is currently $27.3 million. The
plan includes the drilling of 88 new wells, of which 15 will be horizontal.
As of July 26, 2002, the Company had drilled 19 new vertical producing
wells, 8 horizontal wells and 3 service wells (i.e., steam injectors or
water disposal wells). In addition, the Company completed 33 workovers of
existing wells. The planned major refurbishment of one of the two turbines
at the 42 Mwh cogeneration plant was completed in the first quarter of 2002
at a cost of $1.8 million. Also, the Company spent $1.9 million in other
miscellaneous improvements to the Company's producing properties in the
first half of 2002.
The Company has a borrowing base under its credit facility of $150
million, of which $15 million is outstanding and approximately $7 million
is committed for various Letters of Credit, thus the current additional
amount available solely under this facility is approximately $128 million.
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.
11
BERRY PETROLEUM COMPANY
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders
At the annual meeting, which was held at the Company's corporate
offices on May 16, 2002, eleven incumbent directors were re-elected
and an amendment to the Company's stock option plan was approved. The
results of voting as reported by the inspector of elections are noted
below:
1. There were 21,731,888 shares of the Company's capital stock
issued,
outstanding and entitled to vote as of the record date, March 11,
2002.
2. There were present at the meeting, in person or by proxy, the
holders of
20,023,024 shares, representing 92.14% 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 18,447,938 92.13% 1,575,086
Ralph B. Busch, III 18,416,038 91.97% 1,606,986
William E. Bush, Jr. 18,446,938 92.13% 1,576,086
Stephen L. Cropper 18,093,138 90.36% 1,929,886
J. Herbert Gaul, Jr. 18,472,538 92.26% 1,550,486
John A. Hagg 18,441,338 92.10% 1,581,686
Robert F. Heinemann 18,060,436 90.20% 1,962,588
Jerry V. Hoffman 18,473,035 92.26% 1,549,989
Thomas J. Jamieson 18,441,236 92.10% 1,581,788
Roger G. Martin 18,472,738 92.26% 1,550,286
Martin H. Young, Jr. 18,472,938 92.26% 1,550,086
Percentages are based on the shares represented and voting at
the meeting in person or by proxy.
PROPOSAL TWO: Approve the Second Amendment to the Company's Restated
and Amended 1994 Stock Option Plan.
SHARES PERCENT OF PERCENT OF
QUORUM SHARES
VOTES CAST OUTSTANDING
Votes For 16,508,800 82.45% 75.97%
Votes Against 1,463,723 7.31% 6.74%
Votes Abstain 2,050,499 10.24% 9.43%
Broker Non-Vote 2 .00% .00%
Total Votes 20,023,024 100.00% 92.14%
12
BERRY PETROLEUM COMPANY
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K
None
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/ Jerry V. Hoffman
Jerry V. Hoffman
Chairman, President and
Chief Executive Officer
/s/ Ralph J. Goehring
Ralph J. Goehring
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/ Donald A. Dale
Donald A. Dale
Controller
(Principal Accounting Officer)
Date: July 30, 2002
13