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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 September 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 September 30, 2003, was 20,885,522 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
September 30, 2003
INDEX
Page No.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Balance Sheets at September 30, 2003 and
December 31, 2002 3
Condensed Income Statements for the Three Month Periods
Ended September 30, 2003 and 2002 4
Condensed Income Statements for the Nine Month Periods
Ended September 30, 2003 and 2002 5
Condensed Statements of Comprehensive Income for the
Nine Month Periods Ended September 30, 2003 and 2002 5
Condensed Statements of Cash Flows for the
Nine Month Periods Ended September 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 14
PART II. OTHER INFORMATION
Item 4. Controls and Procedures 15
EXHIBIT INDEX
Item 6. Exhibits and Reports on Form 8-K 15
SIGNATURES 16
EX-31.1 Certification of CEO pursuant to Section 302 17
EX-31.2 Certification of CFO pursuant to Section 302 18
EX-32.1 Certification of CEO pursuant to Section 906 19
EX-32.2 Certification of CFO pursuant to Section 906 20
2
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets
(In Thousands, Except Share Information)
Sept 30, December
2003 31, 2002
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 10,568 $ 9,866
Short-term investments available for sale 661 660
Accounts receivable 19,951 15,582
Prepaid expenses and other 4,994 2,597
-------- --------
Total current assets 36,174 28,705
Oil and gas properties (successful efforts
basis), buildings and equipment, net 283,038 228,475
Other assets 2,228 893
-------- --------
$ 321,440 $ 258,073
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 23,061 $ 19,189
Accrued liabilities 4,155 6,470
Federal and state income taxes payable 2,785 2,612
Fair value of derivatives 4,014 4,123
-------- --------
Total current liabilities 34,015 32,394
Long-term liabilities:
Deferred income taxes 37,367 33,866
Long-term debt 55,000 15,000
Abandonment obligations 6,356 4,596
Fair value of derivatives 1,285 159
-------- --------
Total long-term liabilities 100,008 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; 20,885,522 shares issued
and
outstanding at September 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 49,135 49,052
Accumulated other comprehensive loss (3,179) (2,569)
Retained earnings 141,243 125,357
-------- --------
Total shareholders' equity 187,417 172,058
-------- --------
$ 321,440 $ 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 September 30, 2003 and 2002
(In Thousands, Except Per Share Information)
(Unaudited)
2003 2002
Revenues:
Sales of oil and gas $ 33,466 $ 28,044
Sales of electricity 11,120 7,172
Interest and other income, net 350 71
-------- --------
44,936 35,287
Expenses: -------- --------
Operating costs - oil and gas production 16,533 11,402
Operating costs - electricity generation 11,120 7,172
Depreciation, depletion and amortization 5,167 4,126
General and administrative 2,002 2,277
Interest 368 179
-------- --------
35,190 25,156
-------- --------
Income before income taxes 9,746 10,131
Provision for income taxes 1,711 2,544
-------- --------
Net income $ 8,035 $ 7,587
======== ========
Basic net income per share $ .37 $ .35
======== ========
Diluted net income per share $ .36 $ .35
======== ========
Cash dividends per share $ .11 $ .10
======== ========
Weighted average number of shares
of capital stock outstanding (used to
calculate basic net income per share) 21,776 21,746
Effect of dilutive securities:
Stock options 242 166
Other 47 33
-------- --------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 22,065 21,945
======== ========
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
Nine Month Periods Ended September 30, 2003 and 2002
(In Thousands, Except Per Share Information)
(Unaudited)
2003 2002
Revenues:
Sales of oil and gas $ 97,286 $ 73,289
Sales of electricity 34,385 20,963
Interest and other income, net 597 1,616
-------- --------
132,268 95,868
Expenses: -------- --------
Operating costs - oil and gas production 45,343 30,381
Operating costs - electricity generation 34,385 20,631
Depreciation, depletion and amortization 14,350 12,396
General and administrative 6,663 6,171
Recovery of electricity receivables - (3,631)
Dry hole and abandonment 2,487 -
Interest 845 863
-------- --------
104,073 66,811
-------- --------
Income before income taxes 28,195 29,057
Provision for income taxes 4,473 6,023
-------- --------
Net income $ 23,722 $ 23,034
======== ========
Basic net income per share $ 1.09 $ 1.06
======== ========
Diluted net income per share $ 1.08 $ 1.05
======== ========
Cash dividends per share $ .36 $ .30
======== ========
Weighted average number of shares
of capital stock outstanding used to
calculate basic net income per share 21,766 21,738
Effect of dilutive securities:
Stock options 107 149
Other 44 40
-------- --------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 21,917 21,927
======== ========
Condensed Statements of Comprehensive Income
Nine Month Periods Ended September 30, 2003 and 2002
(in Thousands)
(Unaudited)
2003 2002
Net income $ 23,722 $ 23,034
Unrealized losses on derivatives, (net of
income taxes of $407 and $1,968
respectively) (610) (2,953)
-------- --------
$ 23,112 $ 20,081
======== ========
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
Nine Month Periods Ended September 30, 2003 and 2002
(In Thousands)
(Unaudited)
2003 2002
Cash flows from operating activities:
Net income $ 23,722 $ 23,034
Depreciation, depletion and amortization 14,350 12,396
Dry hole and abandonment 2,517 (474)
Deferred income tax liability 3,501 1,414
Other, net (291) 216
-------- --------
Net working capital provided by
operating activities 43,799 36,586
Decrease (increase) in accounts
receivable, prepaid expenses and other (6,808) 2,801
Increase in current liabilities 2,998 2,567
-------- --------
Net cash provided by operating
activities 39,989 41,954
Cash flows from investing activities:
Capital expenditures (24,620) (22,527)
Property acquisitions (47,519) -
Proceeds from sale of assets 1,735 -
Other, net 29 (44)
-------- --------
Net cash used in investing activities (70,375) (22,571)
Cash flows from financing activities:
Proceeds (payment) of long-term debt 40,000 (12,000)
Dividends paid (7,836) (6,522)
Other, net (1,076) (238)
-------- --------
Net cash provided by (used in) financing
activities 31,088 (18,760)
-------- --------
Increase in cash and cash equivalents 702 623
Cash and cash equivalents at beginning of
year 9,866 7,238
-------- --------
Cash and cash equivalents at end of period $ 10,568 $ 7,861
======== ========
Supplemental non-cash activity:
Decrease (increase) in fair value of
derivatives:
Current (net of income taxes of $(44) and
$1,857 in 2003 and 2002, respectively) $ (65) $ 2,786
Non-current (net of income taxes of $450
and $111 in 2003 and 2002, respectively) 675 167
-------- --------
Net decrease to accumulated other
comprehensive income $ 610 $ 2,953
======== ========
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
September 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 September 30,
2003 and December 31, 2002 and results of operations for the three and nine
month periods ended September 30, 2003 and 2002 and cash flows for the nine
month periods ended September 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 and June 30, 2003 Form 10-Q's 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 August 2003, the Company completed the sale of its approximately
43,000 leased acres in Jackson County, Kansas for approximately $1.7
million, while retaining an overriding royalty interest in the property.
The Company recovered its cost in the property.
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.
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 nine months ended September 30, 2003 and
2002 (in thousands, except per share data):
7
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
4. (cont'd)
Three Months Nine Months
Ended Sept 30 Ended Sept 30
2003 2002 2003 2002
Compensation cost, net of income taxes
As reported $ 95 $ 7 $ 203 $ 33
Pro forma 191 205 557 567
Net income:
As reported 8,035 7,587 23,722 23,034
Pro forma 7,939 7,389 23,368 22,500
Basic net income per share:
As reported .37 .35 1.09 1.06
Pro forma .36 .34 1.07 1.04
Diluted net income per share:
As reported .36 .35 1.08 1.05
Pro forma .36 .34 1.07 1.03
5. In August 2003, the Company completed the acquisition from Williams
Production RMT Company of its oil and gas properties located in Brundage
Canyon, Utah in the Uinta Basin for approximately $44.6 million. The
purchase price was adjusted downward from the $48.6 million value at April
1, 2003 due to the net operating income generated from the properties
between April 1st and August 28, 2003, the date of closing. The
properties, located in northeastern Utah, consist of approximately 43,500
net acres, and are producing approximately 2,100 BOE/day of light crude oil
and natural gas as of October 31, 2003. The Company estimated the proved
reserves at 8.6 million BOE (75% light oil and 25% natural gas) as of April
1, 2003.
8
6. In 2002, the Company implemented SFAS No. 143, "Accounting for Asset
Retirement Obligations" for recording future site restoration costs related
to its oil and gas properties. Prior to its implementation, the Company
had recorded the future obligation per SFAS No. 19, "Financial Accounting
and Reporting by Oil and Gas Producing Companies." Under SFAS No. 143, the
following table summarizes the changes in our abandonment obligation for
the nine months ended September 30, 2003:
Nine Months Ended
Sept. 30, 2003
Beginning abandonment obligation Dec. 31, 2002 $ 4,597
Liabilities incurred 1,599
Liabilities settled (202)
Accretion expense 362
________
Ending abandonment obligation Sept. 30, 2003 $ 6,356
========
7. The FASB is currently evaluating the application of certain provisions
of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," to companies in the extractive industries,
including oil and gas companies. The FASB is considering whether the
provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify
costs associated with mineral rights, including both proved and unproved
lease acquisition costs, as intangible assets in the balance sheet, apart
from other oil and gas property costs, and provide specific footnote
disclosures. At the present time, the Company continues to include these
intangible assets in its oil and gas properties.
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
Net income for the third quarter of 2003 was $8 million, or $.37 per
share (basic), on revenues of $44.9 million, up 5% and 23%, from $7.6
million, or $.35 per share (basic), on revenues of $35.3 million in the
third quarter of 2002 and $6.5 million, or $.30 per share (basic), on
revenues of $40.1 million in the second quarter of 2003. Net income for
the first nine months of 2003 was $23.7 million, or $1.09 per share
(basic), on revenues of $132.3 million, up 3% from $23 million, or $1.06
per share (basic), on revenues of $95.9 million for the same period in
2002. Results for the first nine months 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 Waubansee County, Kansas. Pre-
tax income for the first nine months of 2002 include the recovery of $3.6
million of the $6.6 million in electricity receivables which was written
off in the first quarter of 2001.
Three Months Ended Nine Months Ended
Sept 30, June 30, Sept 30 Sept 30, Sept 30,
2003 2003 2002 2003 2002
Oil and gas:
Net Production - BOE per day 16,482 15,397 14,464 15,874 14,110
Per BOE:
Realized sales price(1) $22.07 $21.07 $21.03 $22.45 $19.02
Operating costs (2) 10.21 10.63 8.06 9.88 7.35
Production taxes .69 .52 .51 .58 .54
----- ----- ----- ----- -----
Total operating costs 10.90 11.15 8.57 10.46 7.89
Depreciation/Depletion(DD&A) 3.41 3.38 3.10 3.31 3.22
General & administrative
expenses (G&A) 1.32 1.72 1.71 1.54 1.60
Interest expense .24 .19 .13 .19 .22
Electricity:
Production - Mwh per day 2,127 2,036 2,088 2,100 2,025
Sales - Mwh per day 1,937 1,847 1,918 1,912 1,852
Average sales price - $/Mwh 60.12 62.59 37.59 65.38 38.54
Natural gas cost - $/MMBtu 4.75 5.04 3.02 5.06 2.83
(1) Includes realized hedge losses of $1.90, $1.42 and $1.19 for the
three months ended September 30, 2003, June 30, 2003 and September 30,
2002 and losses of $1.98 and $.58 for the nine months ended September
30, 2003 and 2002, respectively.
(2) Includes monthly expenses in excess of monthly revenues from
cogeneration operations of $2.34, $2.79 and $1.69 for the three months
ended September 30, 2003, June 30, 2003 and September 30, 2002,
respectively and $2.28 and $1.26 for the nine months ended September 30,
2003 and 2002, respectively.
Operating income from oil and gas operations for the third quarter of
2003 was $11.8 million, down 6% from $12.6 million in the third quarter of
2002, but up 28% from $9.2 million in the second quarter of 2003. Operating
income for the first nine months of 2003 was $35.3 million, up 15% from
$30.8 million for the same period in 2002.
10
Oil and gas production (BOE/day) in the third quarter of 2003 was a
record 16,482, up 14% and 7%, respectively from 14,464 in the third quarter
of 2002 and 15,397 in the second quarter of 2003. Production for the first
nine months of 2003 was 15,874, also a Company record, up 13% from 14,110
for the same period of 2002. The increase was attributed primarily to the
Company's 2003 drilling program and the addition of the Brundage Canyon
property in the latter part of the third quarter. On October 31, 2003,
Brundage Canyon was producing approximately 2,100 BOE/day and contributed
700 BOE/day in the third quarter and 236 BOE/day to the Company's 2003 year-
to-date totals. Many of the wells drilled this year on the Company's
California properties have just recently completed their initial steam
cycle and are contributing to further increases in production. Total
Company production for the fourth quarter of 2003 is expected to
approximate 19,000 BOE/day and the average for 2003 is expected to exceed
16,600 BOE/day, a 15% increase over 2002. The Company has targeted an
average production gain for 2004 over 2003 of approximately 20% (without
additional acquisitions) to an average in excess of 20,000 BOE/day.
The average realized sales price per BOE for the Company's crude oil
and natural gas was approximately $22.07 in the third quarter of 2003, up
from $21.03 and $21.07 received in the third quarter of 2002 and the second
quarter of 2003, respectively. The Company primarily is at risk to
reductions in operating income as a result of declines in crude oil and
electricity prices and increases in natural gas prices. To assist in
mitigating these risks, the Company periodically enters into various types
of commodity hedges. See "Item 3. Quantitative and Qualitative Disclosure
About Market Risk" for more information on market risk and existing hedges
for the Company at September 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 $54.32 per Mwh in the
third quarter of 2003 and $61.59 per Mwh for the first nine months of 2003.
The primary benefit of these contracts is that the Company's price received
for electricity produced is based on the cost of natural gas. Therefore,
these contracts contribute to reducing 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. These contracts are scheduled to expire in the
fourth quarter of 2003. Management has requested that these contracts be
extended into 2004. However, if they are not extended, the Company has a
contract in place with a power marketer whereby it can sell its electricity
into the California open market. However, these sales may not be linked to
the cost of natural gas.
Operating costs from oil and gas operations in the third quarter of
2003, were $16.5 million, up from $11.4 million in the third quarter of
2002, and up from $15.6 million in the second quarter of 2003. On a per
BOE basis, operating costs were $10.90 in the third quarter 2003, up from
$8.57 in the third quarter of 2002, but down from $11.15 in the second
quarter of 2003 due primarily to increased production levels. Steam costs
for the third quarter of 2003 remained very high compared to the same
quarter in 2002. The price of natural gas, the largest component of the
cost of generating steam, averaged $4.75 per MMBtu in the third quarter of
2003 compared to $3.02 per MMBtu in the third quarter of
11
2002. The Company has continued to increase steam injection volumes on
its core heavy oil producing assets with average steam injection of 66,000
barrels of steam per day (BSPD) for the third quarter of 2003, up from
62,000 BSPD in the third quarter of 2002. The Company expects operating
costs to average from $10.00 to $10.25 per BOE for the full year of 2003
and to average slightly less than $10.00 per BOE in 2004, assuming natural
gas prices remain at current levels.
DD&A for the third quarter was $5.2 million, or $3.41 per BOE, up from
$4.1 million, or $3.10 per BOE, in the third quarter of 2002 and $4.7
million, or $3.38 per BOE, in the second quarter of 2003. The Company
expects average DD&A per BOE in 2003 to be from $3.40 to $3.50 per BOE and
to rise to an average of $4.40 to $4.70 per BOE for 2004. The increase in
the third quarter of 2003 and projected increase in 2004 are due primarily
to the acquisition of the Brundage Canyon properties.
G&A expenses for the third quarter of 2003 were $2.0 million, or $1.32
per BOE, down from $2.3 million, or $1.71 per BOE, in the third quarter of
2002 and $2.4 million, or $1.72 per BOE, in the second quarter of 2003. On
a per BOE basis, G&A expenses have trended lower primarily due to higher
production levels. Most of the decrease from the third quarter of 2002 was
due to the allocation of various acquisition related costs to successful
acquisition projects. For the first nine months of 2003, G&A expenses were
$6.7 million, or $1.54 per BOE, up from $6.2 million, or $1.60 per BOE, in
the same period of 2002. Management expects G&A expenses for all of 2003
to be approximately $1.50 per BOE and for 2004 to average from $1.30 to
$1.45 per BOE.
The Company completed the sale of approximately 43,000 leased acres in
Jackson County, Kansas in August 2003 for approximately $1.7 million. The
Company recovered its cost in the property while retaining an overriding
royalty interest. The Company has approximately 165,000 leased acres in
Waubansee and Osage County, Kansas. The Company is evaluating locations
for test wells in Osage County and anticipates drilling these wells in
2004. The Company also has a 55,000 acreage position in Illinois and
continues to evaluate its pilot with results expected in 2004.
The Company's effective tax rate of 17% in the third quarter was 2003
and 16% in the first nine months of 2003 compared to 25% and 21% in the
same three and nine month 2002 periods, respectively. The Company
continues to invest in qualifying enhanced oil recovery (EOR) projects and
anticipates that it will continue to earn EOR tax credits. This is the
primary reason that the Company's effective tax rate is below the statutory
tax rate.
Liquidity and Capital Resources
Working capital at September 30, 2003 was $2.2 million, up from ($3.7)
million at December 31, 2002. Net cash provided by operations was $40.0
million for the first nine months of 2003, down slightly from $42.0 million
for the first nine months of 2002. Cash was used for capital expenditures
of $24.6 million, dividends of $7.8 million and net property acquisitions
totaling $47.5 million.
12
The Company has completed a substantial portion of its 2003 drilling
program on its California assets. As of October 26, 2003, 82 wells of a
planned 96 well drilling program have been drilled and completed. In
addition, the Company has drilled 11 new wells in Utah and plans to drill
an additional 15 wells this year. The Company also budgeted 41 workovers
on its California properties and had completed 35 of these projects as of
October 26, 2003. These activities and planned facilities improvements
will bring the total 2003 development budget to approximately $47.1
million.
The Company successfully completed a new $200 million unsecured three
year bank credit facility in July 2003. The facility replaced the previous
$150 million unsecured 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 meet its
growth objectives. In August 2003, the Company drew upon this facility to
finance $40 million of the net $44.6 million purchase price for the
Brundage Canyon, Utah assets. As of September 30, 2003, the Company has
$145 million available under the facility as the outstanding long-term debt
is $55 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.
13
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company enters into various financial contracts to hedge its
exposure to commodity price risk associated with its crude oil production,
electricity production and net natural gas volumes purchased for its
steaming operations. These contracts related to crude oil and natural gas,
have historically been in the form of zero-cost collars and swaps. The
Company generally attempts to hedge between 25% and 50% of its anticipated
crude oil production each year and up to 30% of its anticipated net natural
gas purchased each year. All of these hedges have historically been deemed
to be cash flow hedges with the mark-to-market valuations of the collars
provided by external sources, based on prices that are actually quoted.
Based on the Nymex futures crude oil prices at September 30, 2003, the
Company would expect to make future cash payments of $5.2 million over the
remaining term of its crude oil hedges in place. If the futures prices
decreased 10%, the expected future cash payment under the hedges would
decrease to approximately $.7 million. If the futures prices increased 10%,
the expected future cash payments under the hedges would increase to
approximately $9.9 million. However, at these prices, the Company has
reached the ceiling for the majority of its hedge instruments. Therefore,
if the futures prices increased by 20%, the additional amount the Company
would expect to pay under these hedges would increase by less than $1
million. In addition to its crude oil hedges, the Company has a revenue
sharing agreement on approximately 21% of its production. For every $1
increase or decrease in oil price, the annual effect of this agreement on
companywide oil revenue is approximately $1.1 million.
On the Company's natural gas hedge instruments at September 30, 2003,
the Company would expect to make future cash payments of approximately $.4
million based on the futures natural gas prices. If the futures prices
increased by 10%, the Company would expect to receive approximately $2.0
million under the hedge instruments. If the futures prices decreased by
10%, the Company would expect to pay approximately $2.8 million under these
hedge instruments.
The Company sells approximately 80% of its electricity production, net
of electricity used in its oil and gas operations, under standard offer
contracts to major utilities. These contracts are scheduled to expire on
or before December 31, 2003. However, the Company has requested that these
contracts be extended into 2004. However, if they are not extended, the
Company has a contract in place with a power marketer whereby it can sell
its electricity into the open California market. However, the sales price
under this contract may not be linked to natural gas prices. The Company
sells the remaining 19 Mwh to a utility at $53.70/Mwh plus capacity through
a long-term sales contract.
The Company attempts to minimize credit exposure to counter parties
through monitoring procedures and diversification.
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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 as of the
end of the fiscal quarter covered by this report pursuant to Rule 13a-15 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.
BERRY PETROLEUM COMPANY
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit No. Description
31.1 Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002. *
31.2 Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002. *
32.1 Certification of Chief Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. *
32.2 Certification of Chief Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. *
* Filed herewith
(b) Reports on Form 8-K
On 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.
On August 6, 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 second quarter results
for 2003.
On August 28, 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 closing of the
Company's purchase of the $48.6 million Unita Basin property from Williams
Production RMT Company.
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BERRY PETROLEUM COMPANY
Part II. Other Information
(b) Reports on Form 8-K (Cont'd)
On August 28, 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 the sale
of its interest in 43,000 acres of non-producing coalbed 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: November 6, 2003
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