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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
For the fiscal year ended December 31, 2000
Commission file number 1-9735
BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0079387
(State of incorporation or organization) (I.R.S. Employer Identification Number)
28700 Hovey Hills Road
P.O. Box 925
Taft, California 93268
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (661) 769-8811
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Class A Common Stock, $.01 par value New York Stock Exchange
(including associated stock purchase rights)
Securities registered pursuant to Section 12(g) of the Act: 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 for 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 if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of February 16, 2001, the registrant had 21,134,655 shares of Class A
Common Stock outstanding and the aggregate market value of the voting stock
held by nonaffiliates was approximately $218,111,000. This calculation is
based on the closing price of the shares on the New York Stock Exchange on
February 16, 2001 of $13.90. The registrant also had 898,892 shares of
Class B Stock outstanding on February 16, 2001, all of which is held by an
affiliate of the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
Part III is incorporated by reference from the registrant's definitive
Proxy Statement for its Annual Meeting of Shareholders to be filed, pursuant
to Regulation 14A, no later than 120 days after the close of the registrant's
fiscal year.
BERRY PETROLEUM COMPANY
TABLE OF CONTENTS
PART I
Items 1
and 2. Business and Properties 3
General 3
Oil Marketing 4
Steaming Operations 5
Electricity Contracts 6
Electricity Generation 7
Environmental and Other Regulations 8
Competition 8
Employees 8
Oil and Gas Properties 9
Development 9
Exploration 10
Enhanced Oil Recovery Tax Credits 11
Oil and Gas Reserves 11
Production 11
Acreage and Wells 12
Drilling Activity 12
Title and Insurance 12
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote of Security Holders 13
Executive Officers 13
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters 14
Item 6. Selected Financial Data 15
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
Item 8. Financial Statements and Supplementary Data 20
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 40
PART III
Item 10. Directors and Executive Officers of the Registrant 40
Item 11. Executive Compensation 40
Item 12. Security Ownership of Certain Beneficial Owners
and Management 40
Item 13. Certain Relationships and Related Transactions 40
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 40
2
PART I
Items 1 and 2. Business and Properties
General
Berry Petroleum Company, ("Berry" or "Company"), is an independent energy
company engaged in the production, development, acquisition, exploitation and
exploration of crude oil and natural gas. While the Company was incorporated
in Delaware in 1985 and has been a publicly traded company since 1987, it can
trace its roots in California oil production back to 1909. Currently, Berry's
principal reserves and producing properties are located in Kern, Los Angeles
and Ventura Counties in California. Information contained in this report on
Form 10-K reflects the business of the Company during the year ended
December 31, 2000. The Company's corporate headquarters are located on its
properties in the South Midway-Sunset field, near Taft, California and
Management believes the current facilities are adequate.
The Company's mission is to increase shareholder returns, primarily
through maximizing the value and cash flow of the Company's assets. To
achieve this, Berry's corporate strategy is to remain a low-cost producer
and to grow the Company's asset base strategically. To increase production
and proved reserves, the Company will compete to acquire oil and gas
properties with primarily proved reserves with exploitation potential and
will focus on the further development of its existing properties by
application of enhanced oil recovery (EOR) methods, developmental drilling,
well completions and remedial work. In conjunction with the goals of being
a low-cost heavy oil producer and the exploitation and development of its
large heavy crude oil base, the Company owns three cogeneration facilities
which are intended to provide an efficient and secure long-term supply of
steam which is necessary for the economic production of heavy oil. Berry views
these assets as a critical part of its long-term success. Berry believes that
its primary strengths are its ability to maintain a low-cost operation, its
flexibility in acquiring attractive producing properties which have significant
exploitation and enhancement potential and its experienced management team.
While the Company continues to seek investment opportunities in California,
it is investigating several other basins which would establish another core
area and provide for additional growth opportunities and diversification of
the Company's predominantly heavy oil resource base. The Company has unused
borrowing capacity to finance acquisitions and will consider, if appropriate,
the issuance of capital stock to finance future purchases.
Proved Reserves
As of December 31, 2000, the Company's estimated proved reserves were 107
million barrels of oil equivalent, (BOE), of which 99.3% are heavy crude oil,
i.e., oil with an API gravity of less than 20 degrees. A significant portion
of these proved reserves is owned in fee. Substantially all of the Company's
reserves as of December 31, 2000 were located in California, with 74%, 20% and
5% of total proved reserves in Kern, Los Angeles and Ventura Counties,
respectively. The Company's reserves have a long life, in excess of 20 years,
which is primarily a result of the Company's strong position in heavy crude oil
(the Company's properties in the Midway-Sunset and the Placerita fields average
13 degree API gravity and the Montalvo field averages 16 degree API gravity).
Production in 2000 was 5.5 million BOE, up 7% from 1999 production of 5.1
million BOE. For the five years 1996 through 2000, the Company's average annual
reserve replacement rate was 226% and the finding and development cost was
$2.97 per BOE.
Operations
Berry operates all of its principal oil producing properties. The Midway-
Sunset and Placerita fields contain predominantly heavy crude oil which requires
heat, supplied in the form of steam, injected into the oil producing formations
to reduce the oil viscosity which improves the mobility of the oil flowing to
the well-bore for production. Berry utilizes cyclic steam recovery methods in
the Midway-Sunset field, steam-drive in the Placerita field and primary
recovery methods at its Montalvo field. Berry is able to produce its heavy
oil at its Montalvo field without the necessity of steam since the majority
of the producing reservoir is at a depth in excess of 11,000 feet and thus
the reservoir temperature is high enough to produce the oil without the
assistance of additional heat from steam. Field operations include the
initial recovery of the crude oil and its transport through treating
facilities into storage tanks. After the treating process is completed,
which includes removal of water and solids by mechanical, thermal and
chemical processes, the crude oil is metered through Lease Automatic Custody
Transfer (LACT) units and either transferred into crude oil pipelines owned by
other companies or, in the case of the Placerita field, transported via
trucks. The point-of-sale is usually the LACT unit or truck loading facility.
3
Revenues
The percentage of revenues by source for the prior three years is as follows:
2000 1999 1998
Sales of oil and gas 69% 67% 72%
Sales of electricity 31% 33% 28%
Oil Marketing
The world and California crude oil markets have remained very volatile as
OPEC attempts to manage crude oil prices in the midst of fluctuating inventory
levels and concerns about potential demand weakness due to possible worldwide
economic slowdowns. Oil remained very strong in 2000 with the price for West
Texas Intermediate (WTI), the U.S. benchmark crude oil, averaging $30.26
compared to $19.30 in 1999.
The All American Pipeline, which historically provided an outlet to Texas
markets for California crude oil, was removed from crude oil service in late
1999 and is expected in the future to be utilized for natural gas
transportation into California. In the near term, the reduction of crude oil
shipments from California, coupled with regular refinery maintenance scheduling,
is expected to seasonally increase differentials between WTI and California's
heavy crude, although on an annual basis, the Company believes differentials
will continue in the range of historical norms. The crude price differential
between WTI and California's heavy crude oil continues to be volatile and has
averaged $6.36, $5.97 and $5.97 for 2000, 1999 and 1998, respectively.
Berry markets its crude oil production to competing buyers including
independent marketing, pipeline and oil refining companies. Primarily due to
the Company's ability to deliver significant volumes of crude oil over a
multi-year period, the Company was able to secure a three-year crude sales
agreement, beginning in April 2000, with a major California refiner whereby
the Company sells substantially all of its production under a negotiated
pricing mechanism. The agreement is based on a monthly determination of the
highest price from any of (1) local field posted price plus a fixed bonus,
(2) WTI minus a fixed differential or (3) a fixed percentage of WTI. In
addition to providing a premium above field postings, the agreement effectively
eliminates the Company's exposure to the risk of widening WTI-heavy crude price
differentials.
From time to time, the Company has entered into crude oil hedge contracts,
the terms of which depend on various factors, including Management's view of
future crude oil prices and the Company's future financial commitments. During
2000, the Company maintained two bracketed zero cost collar hedge contracts
with two refiners entered into in previous years as part of its price
protection program. This price protection program was designed to moderate
the effects of a severe price downturn while allowing Berry to participate in
100% of the upside after a maximum $3.00 per barrel payment on 6,500 barrels
per day (BPD). Of this 6,500 BPD, Berry participated on 5,000 BPD above
$15.50 per barrel and on 1,500 BPD above $17.50 per barrel. These price
triggers were based on California heavy oil postings and both contracts
expired at December 31, 2000. These price protection activities resulted in
a net cost to the Company of $1.31 per barrel in 2000 and $0.51 per barrel
in 1999. Berry's 2000 average heavy crude oil sales price was $21.70 in 2000,
up $8.62 per barrel, or 66% from $13.08 in 1999.
At the present time, the Company does not have any crude oil hedges in
place although its existing crude oil sales agreement does provide some
protection against a severe price decline. One of the Company's properties,
with production in excess of 3,000 BPD, is burdened by a price-sensitive
royalty. The royalty is 75% of the heavy oil posted price above $14.02
(for 2001), escalated and calculated annually. Management regularly monitors
the crude oil markets and its financial commitments to determine if, when,
and at what level some form of crude oil hedging or other price protection is
appropriate.
4
Steaming Operations
At December 31, 2000, approximately 95% of the Company's proved reserves,
or 102 million barrels, consisted of heavy crude oil produced from depths
averaging less than 2,000 feet. The Company, in achieving its goal of being
a low-cost heavy oil producer, has focused on reducing its steam cost through
the purchase of its 38 megawatt (Mw) cogeneration facility in 1995 and another
18 Mw cogeneration facility in 1996 as part of the purchase of additional oil
properties in the South Midway-Sunset field. In early 1999, the Company
purchased the Placerita oilfield, this oilfield is highly dependent on
low-cost steam for economic production. This purchase also included a 42 Mw
cogeneration facility. Steam generation from these facilities is more
efficient than conventional steam generators, as both steam and electricity
are produced from the same natural gas fuel supply. In addition, the Company's
ownership of these facilities allows for control over the steam supply which
is crucial for the maximization of oil production and ultimate reserve recovery.
The Company believes that it is advantageous to add additional productive
steam capacity for its requirements at South Midway-Sunset and Placerita to
allow for full development of its properties. It is now clear that California
is considerably short of electrical power in the near future and, as such, the
Company is well positioned to achieve increased electricity revenue through
the expansion of cogeneration steam capacity at strategic locations on the
Company's properties. The Company believes that continued steam generation
from cogeneration facilities will continue to be significantly more efficient
and cost effective than conventional steam generators.
Midway-Sunset Field
For its South Midway-Sunset properties, the Company's steam production for
2000 was generated by its 38 and 18 Mw cogeneration facilities (approximately
21,000 barrels of steam per day (BSPD) including duct-fire) and, as needed,
from conventional steam generators. The Company also has a steam contract
from an on-site, non-owned cogeneration facility for a minimum delivery of
2,000 BSPD for use in the Company's operations, although the facility is
currently not operating. Conventional steam generators are used by the
Company as warranted to maintain current production levels, to economically
produce additional crude oil and as emergency back-up steam generation to the
cogeneration facilities. On its North Midway-Sunset properties, the Company
relies solely on conventional steam generators for its steam requirements.
Placerita
On its Placerita properties, the Company generated approximately 12,500
BSPD in 2000 from its 42 Mw cogeneration facility, may purchase additional
volumes from a third party cogeneration facility when available, and has the
capability of generating another 6,000 BSPD from conventional steam generators.
5
Electricity Contracts
The following is a summary of the Company's cogeneration electrical contracts
and various operational data:
Average Average
Run Time megawatts barrels of
Date Placed Contract under Berry delivered steam
Location Contract(1) Territory In Service Expiration Ownership(2) for sale(3) delivered(3)
Placerita
Placerita I SO2 Edison 3/90 3-2009 >97% 16.7/hour 6,112/day
Placerita II SO2 Edison 5/90 5-2002 >96% 16.4/hour 6,404/day
South Midway-Sunset
Cogen 18 SO2 PG&E 12/87 1-2002 >98% 14.3/hour 6,350/day
Cogen 38 SO1 PG&E 12/86 1-2012 >95% 34.5/hour 15,115/day
(1) SO is for "Standard Offer."
(2) Approximate average through 2000 for Placerita I and II since
February, 1999; Cogen 18 since November, 1996; Cogen 38 since
August, 1995.
(3) Approximate average for 2000 based on 366 day year.
Current Steam Output
Conventional Steam Generation
Effective December 1, 2000, the Company shut-in most of its conventional
steam generation capacity due to an unprecedented increase in natural gas
prices at the Southern California border (SoCal). The natural gas price for
delivery into SoCal was $14.08/Million British Thermal Units (Mmbtu) in
December, versus an average of $2.50/Mmbtu in the first quarter of 2000.
Historically, the SoCal natural gas price has tracked very close to the
NYMEX Henry Hub (HH) price. The SoCal price exploded over HH in December by
approximately $7.72/Mmbtu. Given this dramatic rise in natural gas prices in
California, the Company determined that to maximize cash flow, it was
necessary to suspend most of its conventional steaming operations. Continued
high natural gas prices in California, far in excess of HH, have persisted
into 2001. As of this writing, the Company has not returned its conventional
steam generation to operation.
Cogeneration Steam Generation
While higher natural gas prices also increased the Company's steam cost
from its cogeneration facilities, it is not so dramatic as for conventional
steam operations. The pricing of electricity under the Company's Standard
Offer (SO) contracts is based primarily on natural gas costs, thus, as fuel
costs rise so do the electrical revenues. Steam from the Company's
cogeneration facilities is generally economic even at high natural gas prices.
The much-publicized California electricity crisis, with California's two
largest utilities (Pacific Gas and Electric Company (PG&E) and Southern
California Edison Company (Edison)) nearing bankruptcy, has negatively impacted
Berry and its operations. Edison failed to pay Berry for November and December
2000 power deliveries, which were due in early January and February 2001,
respectively. In addition, they have also failed to pay for January 2001
deliveries, which were due in early March. PG&E made full payment for November
2000 and only partial payments, of approximately 15%, for December 2000 and
January 2001 deliveries.
In response to non-payment and to preserve cash flow, the Company suspended
operations at its 38 Mw and Placerita Unit II (21 Mw) cogeneration facilities
effective February 1, 2001. The Company also suspended operations at its 18 Mw
cogeneration facility on February 17, 2001. The Company has notified both
utilities that they are in breach of the power purchase agreements and full
payment is expected as soon as possible. The Company anticipates that its
thermally-dependent oil production will begin to decline in the first quarter
of 2001 due to this significant reduction of steam injection into its heavy
oil reservoirs.
6
The Company has physical access to gas pipelines, such as the Kern River/
El Paso and Southern California Gas Company systems, to transport its gas
purchases required for steam generation. The Company has no long-term gas
delivery contracts and none of the Company's cogeneration facilities are
subject to any long-term gas transportation agreements. Historically, there
has been sufficient capacity to deliver adequate quantities of natural gas to
the Company's properties, however, it appears that, pipeline capacity into and
within California is currently constrained and may be partially responsible
for higher natural gas prices in California. The Company has no assurance
currently that it can procure its future natural gas requirements at
reasonable prices.
Electricity Generation
The Company's three cogeneration facilities, when combined, have
electricity production capacity of 98 Mw of electricity per hour. Each
facility is centrally-located on an oil property such that the steam generated
by the facility is capable of being delivered to the oil properties that
require the steam for production purposes. With higher natural gas prices
impacting its operations so significantly, the Company is pursuing other
opportunities to secure additional long-term sources of low-cost steam.
The Company's investments in its cogeneration facilities have been for the
express purpose of lowering the steam costs in its heavy oil operations and
securing operating control of the respective steam generation. For these
reasons, proceeds received from the sale of electricity have been reported
as a reduction to operating costs - oil and gas production in prior years.
However, with the significant increases in electricity and natural gas prices
that have occurred over the last year, the significantly changed electrical
situation in California, and with the Company pursuing various options to
sell its electricity now that its power purchasers have breached the Company's
contracts, the Company has modified its financial statement presentation to
assist investors in understanding the electrical impact to the Company's
business. The Company now reports its electricity proceeds and costs thereof
separately. Proceeds from the sale of electricity are now reported as
revenues in the Company's financial statements. Expenses of operating the
cogeneration plants are analyzed monthly by field of operations. Any profits
generated from cogeneration are considered profits from electricity generation.
If the expenses exceed electricity revenues, the excess expenses are charged
to oil and gas operating costs.
During the fourth quarter of 2000, the Company experienced a significant
increase in the cost of natural gas, which is used as fuel for its cogeneration
plants and steam generators. To protect itself from a pending proposed
decision by a CPUC board member which would have had the effect of de-linking
the Company's natural gas cost from electricity sales under its standard offer
contracts, the Company entered into several derivative contracts to hedge
4,500 Mmbtu/day of natural gas purchases for the three months ended March 31,
2001. During December 2000, the Company recorded operating costs of
$.3 million related to the ineffective portion of these derivative instruments.
Additionally, the Company recorded $.4 million (net of tax effect) in other
comprehensive income related to unrecognized gains from these derivative
instruments. See Notes 2 and 3 to the financial statements.
The Company's immediate challenge is to locate a creditworthy buyer for
its electricity and return its cogeneration facilities to operating status.
The current market conditions surrounding electricity generation and sales
are dominated by the legislative activity in Sacramento, California's capital.
There remain major hurdles before California's electrical marketplace can
return to some sort of normalcy. Berry is working vigorously with industry
groups and state legislators in an effort to return its cogeneration
facilities to profitable operating status as soon as possible.
Management believes that it should be able to return its cogeneration
facilities to full operational status by the summer of 2001, as electrical
supply is expected to be in high demand and problems collecting payments for
electricity sales will hopefully be resolved. However, with all of the
current uncertainty and turmoil that exists in the California electrical
marketplace, Management can provide no assurance as to the timing and nature
of the resolution of the electrical crisis, including but not limited to the
return of its cogeneration facilities to full operation or the collection of
payments for electricity sales.
The Company is pursuing various opportunities to expand its cogeneration
capacity. The Company has a long-term need for additional substantial volumes
of steam to maximize its oil production and desires to secure this steam
through cogeneration.
7
Environmental and Other Regulations
Berry Petroleum Company is committed to conducting its operations in a
manner that protects the health and safety of employees, contractors, the
public, and the quality of the environment in its operating areas. Berry
Petroleum Company makes environmental, health and safety protection an
integral part of all business activities, from the acquisition and management
of its resources through the decommissioning and reclamation of its wells and
facilities.
Berry's operations are affected by federal, state, regional and local laws
and regulations, including laws that govern, among other things, the issuance
of permits in connection with drilling, production, electricity generation
and equipment operation, allowable rates of production and land use
restrictions. Also, the amounts and types of substances that may be released
into the environment, the discharge and disposal of waste materials, the
reclamation and abandonment of wells and facilities, the remediation of
contaminated sites and other laws relating to the petroleum industry. Berry
is further affected by changes in such laws and by constantly changing
administrative regulations. Furthermore, these agencies may impose
substantial liabilities if the Company fails to comply with such regulations
or for any contamination resulting from the Company's operations.
Berry has established policies and procedures that focus on preventing
environmental impacts, and, when required, on timely remediation. The costs
incurred to ensure compliance with environmental, health and safety laws and
other regulations are inextricably connected to normal operating expenses such
that the Company is unable to separate the expenses related to these matters.
Although environmental, health and safety requirements do have a
substantial impact upon the energy industry, generally these requirements do
not appear to affect the Company any differently, or to any greater or lesser
extent, than other companies in California and in the domestic oil and gas
industry, as a whole. Berry believes that compliance with environmental laws
and regulations will not have a material adverse effect on the Company's
operations or financial condition but there can be no assurances that changes
in, or additions to, laws or regulations regarding the protection of the
environment will not have such an impact in the future.
Berry maintains insurance coverage that it believes is customary in the
industry although it is not fully insured against all environmental or other
risks. The Company is not aware of any environmental claims existing as of
December 31, 2000 that would have a material impact upon the Company's
financial position, results of operations, or liquidity.
Competition
The oil and gas industry is highly competitive. As an independent
producer, the Company does not own any refining or retail outlets and,
therefore, it has little control over the price it receives for its crude oil.
As such, higher costs, fees and taxes assessed at the producer level cannot
necessarily be passed on to the Company's customers. In acquisition
activities, significant competition exists as integrated and independent
companies, individual producers and operators are active bidders for desirable
oil and gas properties. Although many of these competitors have greater
financial and other resources than the Company, Management believes that Berry
is in a position to compete effectively due to its low cost structure,
transaction flexibility, strong financial position, experience and
determination.
Employees
On December 31, 2000, the Company had 115 full-time employees, up from
108 employees at year-end 1999.
8
Oil and Gas Properties
Development
Midway-Sunset - Berry owns and operates working interests in 35 properties
consisting of 3,985 acres located in the Midway-Sunset field. The Company
estimates these properties account for approximately 74% of the Company's
proved oil and gas reserves and approximately 74% of its current daily
production. Of these properties, 18 are owned in fee. The wells produce
from an average depth of approximately 1,200 feet, and rely on thermal EOR
methods, primarily cyclic steaming.
During 2000, the primary focus in this field was directed at the continued
development of the Formax properties acquired in 1996 and the continued
application of horizontal well technology in the Monarch sands. Of the 79
wells drilled in this field in 2000, 25 were drilled on the Formax properties,
and 16 were horizontal wells. The Company's objectives using this developing
technology are to improve ultimate recovery of original oil-in-place, reduce
the development and operating costs of the properties and accelerate
production. In 2001, the Company plans to drill an additional 21 development
wells in this field, 9 of which will be horizontal.
During 2000, three of the wells drilled were exploitation wells in the
north end of the field to further evaluate the diatomite accumulation on top
of the Fairfield anticline and several other targets. In 2001, one of the
wells planned for drilling is a diatomite core well to further delineate this
accumulation.
Placerita - Following acquisition of this significant field early in 1999,
the Company made significant progress in 2000 on delineation of the remaining
potential. The property consists of six leases (three federal) and three fee
properties (one of which we acquired in 2000) totaling approximately 750 acres.
The Company estimates current proved reserves from Placerita account for
approximately 21% of Berry's proved oil and gas reserves and approximately
21% of Berry's daily production. The average depth of these wells is 1800 feet
and the properties rely extensively on thermal methods, primarily steam
flooding.
The Company drilled two wells in 2000, one of which was the first
horizontal ever drilled in the field. For 2001, the Company plans to drill
four wells to initiate phase one of our major development campaign at the
north end of the field.
Montalvo - Berry owns a 100% working interest in six leases, totaling
8,563 acres, in Ventura County, California comprising the Montalvo field.
The State of California is the lessor for two of the six leases. The Company
estimates current proved reserves from Montalvo account for approximately 5%
of Berry's proved oil and gas reserves and approximately 5% of Berry's daily
production. The wells produce from an average depth of approximately
11,500 feet. No new wells were drilled in 2000 and at this time, the Company
has no firm plans for drilling or redrilling at Montalvo in 2001.
9
The following is a summary of capital expenditures incurred during 2000
and 1999 and projected capital expenditures for 2001. While the Board approved
a 2001 budget of approximately $25 million in December 2000, the Company
currently anticipates a much lower budget of approximately $11 million. This
reduced budget is in direct response to extremely high natural gas prices in
California and, more importantly, the contract breach and the ongoing
non-payment by PG&E and Edison for power deliveries made in late 2000 and
early 2001. As these conditions change, Berry will reevaluate its capital
expenditure program.
CAPITAL EXPENDITURES SUMMARY
(in thousands)
2001(1) 2000 1999
(Projected)
South Midway-Sunset Field
New wells $ 3,800 $ 10,128 $ 3,120
Remedials/workovers 900 1,373 607
Facilities 2,850 1,333 3,463
------- ------- -------
7,550 12,834 7,190
------- ------- -------
Placerita
New wells 1,950 2,669 310
Remedials/workovers 250 1,001 69
Facilities 730 4,543 784
------- ------- -------
2,930 8,213 1,163
------- ------- -------
North Midway-Sunset Field
New wells 150 1,257 150
Remedials/workovers 0 212 25
Facilities 75 76 18
------- ------- -------
225 1,545 193
------- ------- -------
Montalvo
Remedials/workovers 0 420 16
Facilities 166 1,295 37
------- ------- -------
166 1,715 53
------- ------- -------
Other 0 946 523
------- ------- -------
Totals $ 10,871 $ 25,253 $ 9,122
======= ======= =======
(1) Budgeted capital expenditures may be adjusted for numerous reasons
including, but not limited to, oil, natural gas and electricity price levels.
See Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Exploration
The Company did not participate in the drilling of any exploratory wells
in 2000 or 1999 and has none budgeted for 2001. In recent years, the Company
has concentrated on growth through development of existing assets and strategic
acquisitions. The Company is pursuing an acquisition strategy which may
include some exploration drilling in the future.
10
Enhanced Oil Recovery Tax Credits
The Revenue Reconciliation Act of 1990 included a tax credit for certain
costs associated with extracting high-cost, capital-intensive marginal oil or
gas and which utilizes at least one of nine designated "enhanced" or tertiary
recovery methods. Cyclic steam and steam drive recovery methods for heavy
oil, which Berry utilizes extensively, are qualifying EOR methods. In 1996,
California conformed to the federal law, thus, on a combined basis, the
Company is able to achieve credits approximating 12% of its qualifying costs.
The credit is earned for only qualified EOR projects by investing in one of
three types of expenditures: 1) drilling development wells, 2) adding
facilities that are integrally related to qualified EOR production, or
3) utilizing a tertiary injectant, such as steam, to produce oil. The credit
may be utilized to reduce the Company's tax liability down to, but not below,
its alternative minimum tax liability. This credit is significant in reducing
the Company's income tax liabilities and effective tax rate.
Oil and Gas Reserves
The Company continued to engage DeGolyer and MacNaughton (D&M) to estimate
the proved oil and gas reserves and the future net revenues to be derived from
properties of the Company for the year ended December 31, 2000. D&M is an
independent oil and gas consulting firm located in Dallas, Texas. In
preparing their reports, D&M reviewed and examined geologic, economic,
engineering and other data considered applicable to properly determine the
reserves of the Company. They also examined the reasonableness of certain
economic assumptions regarding forecasted operating and development costs and
recovery rates in light of the economic environment on December 31, 2000.
For the Company's operated properties, these reserve estimates are filed
annually with the U.S. Department of Energy. Refer to the Supplemental
Information About Oil & Gas Producing Activities (Unaudited) for the
Company's oil and gas reserve disclosures.
Production
The following table sets forth certain information regarding production
for the years ended December 31, as indicated:
2000 1999 1998
Net annual production:(1)
Oil (Mbbls) 5,434 5,060 4,359
Gas (Mmcf) 199 180 245
Total equivalent barrels( 5,467 5,090 4,399
Average sales price:
Oil (per bbl) $ 21.70 $ 13.08 $ 9.02
Gas (per mcf) 4.34 1.90 2.64
Per BOE 21.72 13.07 9.05
Average operating cost - oil and gas
production (per BOE)(3) 8.56 5.64 4.15
(1) Net production represents that owned by Berry and produced to its
interest, less royalty and other similar interests.
(2) Equivalent oil and gas information is at a ratio of 6 thousand cubic feet
(mcf) of natural gas to 1 barrel (bbl) of oil. A barrel of oil (bbl) is
equivalent to 42 U.S. gallons.
(3) Includes monthly expenses in excess of monthly revenues from cogeneration
operations (per BOE) of $0.89, $0.17 and $0.14 for 2000, 1999 and 1998,
respectively. See Note 2 to the financial statements.
11
Acreage and Wells
At December 31, 2000, the Company's properties accounted for the following
developed and undeveloped acres:
Developed Acres Undeveloped Acres
Gross Net Gross Net
California 7,206 7,206 7,244 7,244
Other 360 41 - -
------ ------ ------ ------
7,566 7,247 7,244 7,244
====== ====== ====== ======
Gross acres represent acres in which Berry has a working interest; net
acres represent Berry's aggregate working interests in the gross acres.
Berry currently has 2,472 gross oil wells (2,468 net) and 4 gross gas
wells (3.1 net). Gross wells represent the total number of wells in which
Berry has a working interest. Net wells represent the number of gross wells
multiplied by the percentages of the working interests owned by Berry. One
or more completions in the same bore hole are counted as one well. Any well
in which one of the multiple completions is an oil completion is classified
as an oil well.
Drilling Activity
The following table sets forth certain information regarding Berry's
drilling activities for the periods indicated:
2000 1999 1998
Gross Net Gross Net Gross Net
Exploratory wells drilled:
Productive - - - - - -
Dry(1) - - - - - -
Development wells drilled:
Productive 81 81 21 21 20 20
Dry(1) - - - - 1 1
Total wells drilled:
Productive 81 81 21 21 20 20
Dry(1) - - - - 1 1
(1) A dry well is a well found to be incapable of producing either oil or gas
in sufficient quantities to justify completion as an oil or gas well
Title and Insurance
To the best of the Company's knowledge, there are no defects in the title
to any of its principal properties including related facilities.
Notwithstanding the absence of a recent title opinion or title insurance
policy on all of its properties, the Company believes it has satisfactory
title to its properties, subject to such exceptions as the Company believes
are customary and usual in the oil and gas industry and which the Company
believes will not materially impair its ability to recover the proved oil and
gas reserves or to obtain the resulting economic benefits.
The oil and gas business can be hazardous, involving unforeseen
circumstances such as blowouts or environmental damage. Although it is not
insured against all risks, the Company maintains a comprehensive insurance
program to address the hazards inherent in operating its oil and gas business.
12
Item 3. Legal Proceedings
While the Company is, from time to time, a party to certain lawsuits in
the ordinary course of business, the Company does not believe any of such
existing lawsuits will have a material adverse effect on the Company's
operations, financial condition, or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Executive Officers
Listed below are the names, ages (as of December 31, 2000) and positions
of the executive officers of Berry and their business experience during at
least the past five years. All officers of the Company are appointed in May
of each year at an organizational meeting of the Board of Directors. There
are no family relationships between any executive officer and members of the
Board of Directors.
JERRY V. HOFFMAN, 51, Chairman of the Board, President and Chief Executive
Officer. Mr. Hoffman has been President and Chief Executive Officer since
May 1994 and President and Chief Operating Officer from March 1992 until
May 1994. Mr. Hoffman was added to the Board of Directors in March 1992 and
named Chairman in March 1997. Mr. Hoffman held the Senior Vice President and
Chief Financial Officer positions from January 1988 until March 1992.
RALPH J. GOEHRING, 44, Senior Vice President and Chief Financial Officer.
Mr. Goehring has been Senior Vice President since April 1997, Chief Financial
Officer since March 1992 and was Manager of Taxation from September 1987
until March 1992. Mr. Goehring is also an Assistant Secretary for the
Company.
MICHAEL R. STARZER, 39, has been Vice President of Corporate Development
since March 1996 and was Manager of Corporate Development from April 1995 to
March 1996. Mr. Starzer, a registered petroleum engineer, was with Unocal
from August 1983 to May 1991 and from August 1993 to April 1995. Mr. Starzer
was an engineering consultant and worked with the California State Lands
Commission from May 1991 to August 1993.
BRIAN L. REHKOPF, 53, has been Vice President of Engineering since March
2000 and was Manager of Engineering from September 1997 to March 2000.
Mr. Rehkopf, a registered petroleum engineer, joined the Company's engineering
department in June 1997 and was previously a Vice President and Asset Manager
with ARCO Western Energy, a subsidiary of Atlantic Richfield Corp. (ARCO)
since 1992 and an Operations Engineering Supervisor with ARCO from 1988
to 1992. Mr. Rehkopf is also an Assistant Secretary for the Company.
GEORGE T. CRAWFORD, 40, has been Vice President of Production since
December 2000 and was Manager of Production, from January 1999 to
December 2000. Mr. Crawford, a petroleum engineer, was previously the
Production Engineering Supervisor for ARCO Western Energy. Mr. Crawford was
employed by ARCO from 1989 to 1998 in numerous engineering and operational
assignments including Production Engineering Supervisor, Planning and
Evaluation Consultant and Operations Superintendent.
DONALD A. DALE, 54, has been Controller since December 1985.
KENNETH A. OLSON, 45, has been Corporate Secretary since December 1985
and Treasurer since August 1988.
13
PART II
Item 5. Market for the Registrant's Common Equity and Related Shareholder
Matters
Shares of Class A Common Stock (Common Stock) and Class B Stock, referred
to collectively as the "Capital Stock," are each entitled to one vote and 95%
of one vote, respectively. Each share of Class B Stock is entitled to a
$1.00 per share preference in the event of liquidation or dissolution.
Further, each share of Class B Stock is convertible into one share of Common
Stock at the option of the holder.
In November 1999, the Company adopted a Shareholder Rights Agreement and
declared a dividend distribution of one such Right for each outstanding share
of Capital Stock on December 8, 1999. Each share of Capital Stock issued
after December 8, 1999 includes one Right. The Rights expire on December 8,
2009. See Note 7 of Notes to the Financial Statements.
In conjunction with the acquisition of the Tannehill assets in 1996, the
Company issued a Warrant Certificate to the beneficial owners of Tannehill Oil
Company. This Warrant authorizes the purchase of 100,000 shares of Berry
Petroleum Company Class A Common Stock until November 8, 2003 at $14.06 per
share. All the warrants are currently outstanding and the underlying shares
will not be registered under the Securities Act of 1933.
Berry's Class A Common Stock is listed on the New York Stock Exchange
under the symbol "BRY". The Class B Stock is not publicly traded. The market
data and dividends for 2000 and 1999 are shown below:
2000 1999
Price Range Dividends Price Range Dividends
High Low per Share High Low per Share
First Quarter $ 17 7/8 $ 14 1/16 $ .10 $ 14 1/8 $ 8 11/16 $ .10
Second Quarter 17 5/16 14 5/8 .10 14 5/8 11 1/8 .10
Third Quarter 19 7/8 16 1/2 .10 14 11/16 13 1/8 .10
Fourth Quarter 18 3/16 11 5/8 .10 15 7/16 12 1/4 .10
The closing price per share of Berry's Common Stock, as reported on the
New York Stock Exchange Composite Transaction Reporting System for
February 16, 2001, December 31, 2000 and December 31, 1999 was $13.90,
$13 3/8 and $15 1/8, respectively.
The number of holders of record of the Company's Common Stock was 745
(and approximately 3,600 street name shareholders) as of February 16, 2001.
There was one Class B Stockholder of record as of February 16, 2001.
The Company paid cash dividends for many years prior to the roll-up on
December 16, 1985 of the various Berry companies into Berry Petroleum Company.
Since Berry's formation, the Company has paid dividends on its Common
Stock for eight consecutive semi-annual periods through September 1989 and
for 45 consecutive quarters through December 31, 2000. The Company intends
to continue the payment of dividends, although future dividend payments will
depend upon the Company's level of earnings, operating cash flow, capital
commitments, financial covenants and other relevant factors.
At December 31, 2000, dividends declared on 4,000,894 shares of certain
Common Stock are restricted, whereby 37.5% of the dividends declared on these
shares are paid by the Company to the surviving member of a group of
individuals, the B group, for as long as this remaining member shall live.
14
Item 6. Selected Financial Data
The following table sets forth certain financial information with respect
to the Company and is qualified in its entirety by reference to the historical
financial statements and notes thereto of the Company included in Item 8,
"Financial Statements and Supplementary Data." The statement of operations
and balance sheet data included in this table for each of the five years in
the period ended December 31, 2000 were derived from the audited financial
statements and the accompanying notes to those financial statements
(in thousands, except per share, per BOE and % data):
2000 1999 1998 1997 1996
Statement of Operations Data:
Sales of oil and gas $ 118,801 $ 66,615 $ 39,858 $ 67,172 $ 55,264
Sales of electricity 52,765 33,731 15,680 17,190 11,552
Operating costs - oil and gas
production 46,789 28,697 18,272 22,589 18,203
Operating costs - electricity
generation 48,614 27,062 15,236 17,008 10,936
General and administrative
expenses(G&A) 7,754 6,269 3,975 5,907 4,820
Depreciation, depletion
& amortization (DD&A) 14,030 12,294 10,080 10,138 7,323
Net income 37,183 18,006 3,879 19,260 17,546
Basic net income per share 1.69 .82 .18 .88 .80
Weighted average number of
shares outstanding 22,029 22,010 22,007 21,976 21,939
Balance Sheet Data:
Working capital $ (1,154) $ 8,435 $ 9,081 $ 11,499 $ 7,850
Total assets 238,359 207,649 173,804 177,724 176,403
Long-term debt 25,000 52,000 30,000 32,000 36,000
Shareholders' equity 145,224 116,213 106,924 111,871 101,009
Cash dividends per share .40 .40 .40 .40 .40
Operating Data:
Cash flow from operations 65,934 24,809 19,924 31,401 29,182
Capital expenditures
(excluding acquisitions) 25,253 9,122 6,981 18,597 9,333
Property/facility
acquisitions 3,182 33,605 2,991 - 75,613
Oil and gas producing
operations(per BOE):
Average sales price $ 21.72 $ 13.07 $ 9.05 $ 14.71 $ 15.36
Average operating costs(1) 8.56 5.64 4.15 4.96 5.09
G&A 1.42 1.23 .90 1.30 1.35
Cash flow 11.74 6.20 4.00 8.45 8.92
DD&A 2.57 2.42 2.29 2.23 2.05
Operating income $ 9.17 $ 3.78 $ 1.71 $ 6.22 $ 6.87
Production (BOE) 5,467 5,090 4,399 4,550 3,573
Production (Mw) 764 728 448 446 412
Proved Reserves Information:
Total BOE 107,361 112,541 92,609 101,043 102,116
Present value (PV10) of
estimated future cash flow
before income taxes $ 721,770 $ 714,555 $ 113,811 $ 376,459 $ 634,579
Year-end average BOE price for
PV10 purposes 20.63 19.41 7.05 12.19 18.37
Other:
Return on average shareholders'
equity 28.5% 16.5% 3.5% 18.1% 18.2%
Return on average total assets 16.8% 9.0% 2.2% 10.9% 13.3%
Total debt/total debt plus equity 14.7% 30.9% 21.9% 22.2% 29.8%
Year-end stock price $ 13 3/8 $ 15 1/8 $ 14 3/16 $ 17 7/16 $ 14 3/8
Year-end market capitalization $ 294,699 $ 332,920 $ 312,247 $ 383,510 $ 315,471
(1)Including monthly expenses in
excess of monthly revenues
from cogeneration operations $ 0.89 $ 0.17 $ 0.14 $ 0.48 $ 0.23
15
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion provides information on the results of operations
for each of the three years ended December 31, 2000, 1999 and 1998 and the
financial condition, liquidity and capital resources as of December 31, 2000
and 1999. The financial statements and the notes thereto contain detailed
information that should be referred to in conjunction with this discussion.
The profitability of the Company's operations in any particular accounting
period will be directly related to the average realized prices of oil, gas and
electricity sold, the type and volume of oil and gas produced and electricity
generated and the results of acquisition, development, exploitation and
exploration activities. The average realized prices for oil, natural gas
and electricity will fluctuate from one period to another due to regional
market conditions and other factors, while oil prices will also be strongly
influenced by world supply and demand. The aggregate amount of oil and gas
produced may fluctuate based on the success of development and exploitation
of oil and gas reserves pursuant to current reservoir management. The cost
of natural gas used in the Company's steaming operations and electrical
generation, production rates, labor, maintenance expenses and production
taxes are expected to be the principal influences on operating costs.
Accordingly, the results of operations of the Company may fluctuate from
period to period based on the foregoing principal factors, among others.
Results of Operations
Net income for the year 2000 was $37.2 million, up 107% and 854%,
respectively, from $18 million in 1999 and $3.9 million in 1998. Net income
rose 22% to $9.9 million in the fourth quarter of 2000 from $8.1 million in
the fourth quarter of 1999. Results for the year 2000 represented the highest
net income, cash flow and production ever achieved by the Company in any
fiscal year and the fourth quarter was the sixth quarter in a row of
increasing net income. Record net income for the year and the fourth quarter
were primarily related to record production volumes sold at historically high
oil prices.
The following table presents certain operating data for the years ended
December 31, 2000, 1999 and 1998:
2000 1999 1998
Net production - BOE/D 14,937 13,946 12,053
Per BOE:
Average sales price $ 21.72 $ 13.07 $ 9.05
Operating costs(1) 8.13 5.12 3.56
Production taxes .43 .52 .59
Total operating costs 8.56 5.64 4.15
DD&A 2.57 2.42 2.29
G&A 1.42 1.23 .90
Interest expense .58 .78 .44
(1)Including monthly expenses in excess of monthly
revenues from cogeneration operations of $0.89, $0.17 and
$0.14 in 2000, 1999 and 1998, respectively.
BOE/D - Barrels of oil equivalent per day
Operating income from oil and gas producing operations of $58.3 million
was up $32.4 million, or 125%, from $25.9 million in 1999 and up $46.5 million,
or 394% from $11.8 million in 1998. The improvement in 2000 compared with
both 1999 and 1998 was due to higher oil prices and higher production,
partially offset by higher operating costs. The average price received per
BOE in 2000 was $21.72, dramatically higher than $13.07 in 1999 and the
historical low of $9.05 in 1998 and represented the highest average price
ever for the Company's hydrocarbon production. These prices are net of
hedging costs of $1.31 and $.51 per BOE for 2000 and 1999, respectively, and
include the profit from hedging of $.48 for 1998. These three years
dramatically demonstrate the high degree of price volatility for the
Company's crude oil.
16
The second factor which increased the Company's operating income for the
year was the increase in production volumes achieved by the Company. The
Company achieved production on a BOE/D basis for 2000 of 14,937, up from
13,946 in 1999 and 12,053 in 1998. On a percentage basis, these results were
a 7% and 24% increase over 1999 and 1998 levels, respectively. The Company's
purchase of the Placerita properties in February 1999, which currently produce
approximately 3,500 BOE/D, and total Company development costs of over $34
million in 1999 and 2000 were the primary contributing factors to the
production increases over 1998 levels.
Operating costs per barrel in 2000 were $8.56, up from $5.64 for 1999
and $4.15 in 1998. The largest factors in the increase in 2000 compared to
1999 was a substantial increase in the price of natural gas used to fire the
Company's cogeneration facilities and conventional steam generators, the cost
of running conventional generators close to capacity, the added cost of
operating the Company's marginal producers and certain environmental costs,
3D seismic costs and general cost increases in contractor services. Gas
prices/Mmbtu averaged $4.89 in 2000, up 80% and 115% from $2.71 in 1999
and $2.27 in 1998, respectively. Effective December 1, 2000, average gas
costs for the Company reached $14.14 per Mmbtu. The price of natural gas at
the SoCal border broke out of its long-term historical linkage of
approximating the NYMEX Henry Hub (HH) price. In December, the SoCal border
price exceeded the HH price by approximately $7.30/Mmbtu, and has continued
to average over $5.00/Mmbtu above HH. This phenomena is having significant
negative impacts on heavy oil production in California and has significantly
contributed to escalating electricity prices in the Western United States.
Due to these unprecedented, extraordinarily high natural gas prices, the
Company has curtailed most of its conventional steam generation. High natural
gas prices have continued into the first quarter of 2001 and have rendered
conventional steam generation uneconomic even at the current strong oil prices.
The Company intends to resume operation of these steam generators as soon as
it is economic to do so.
The Company's cogeneration facilities operated close to 100% of the time,
not covered by scheduled outages, for all of 2000. The Company's cogeneration
facilities sell power under standard offer contracts which link electricity
payments to the price of natural gas at the SoCal border. Thus, the economics
of producing steam via cogeneration facilities under these contracts is
superior to conventional steam generation. The much publicized California
electricity crisis, with California's two largest utilities (PG&E and Edison)
nearing bankruptcy, has negatively impacted Berry and its operations. Edison
failed to pay Berry for November and December 2000 power deliveries, which
were due in early January and February 2001, respectively. In addition, they
also failed to pay for January 2001 deliveries which were due in early March.
PG&E made full payments for November 2000 and only partial payments, of
approximately 15%, for December 2000 and January 2001 deliveries. Effective
February 1, 2001, Management determined that it was not in the Company's best
interest to operate its 38 Mw facility at its South Midway-Sunset field nor
one of its 21 Mw units at Placerita. In addition, effective February 17, 2001,
the Company's 18 Mw facility, also located at its South Midway-Sunset field
was also shut down.
While the Company's future thermal oil production will suffer as a
result of the significant withdrawal of steam from the oil reservoir, the
Company will not allow its strong financial condition to materially
deteriorate while waiting for a political solution to California's much
publicized electricity crisis. The Company is vigorously pursuing every
opportunity to restart its cogeneration facilities and sell its power to a
creditworthy purchaser.
The Company implemented a record capital budget in the year 2000 of
$25.3 million. Of this total, $24.3 million was spent on well development
and facility enhancements. During 2000, 81 new wells were drilled, including
17 horizontal wells and 76 workovers were completed on existing wells. As
was discussed above, these expenditures were instrumental in improving
production to over 17,000 barrels per day at year-end 2000 and should result
in increasing the ultimate recovery of oil from the Company's properties.
Depreciation, depletion and amortization (DD&A) on a per barrel basis
increased to $2.57, up from $2.42 in 1999 and $2.29 in 1998. The increase
from prior years, which is calculated on a units of production basis, was
primarily due to production acceleration achieved through increased steaming
and development activity and the higher capital program. The Company
believes that its DD&A rate per barrel for 2001 will be similar or slightly
higher than its 2000 rate.
17
General
General and administrative (G&A) expenses in 2000 were $7.8 million, up
24% and 95% from $6.3 million in 1999 and $4 million in 1998. On a per barrel
basis, these results equate to $1.42 in 2000, up from $1.23 in 1999 and $.90 in
1998. The primary reasons for the increase were higher salaries, the hiring of
additional employees and higher legal fees, the majority of which related to a
lawsuit that was settled in the first quarter of 2000 and which arose from a
company that Berry purchased in 1988. In 1998, the Company reduced salaries,
staff and numerous other costs to preserve cash flow in the low oil price
environment. These measures resulted in very low, but unsustainable G&A
costs on a per barrel basis.
Interest expense fell to $3.2 million in 2000 from $4.0 million in 1999,
but remained higher than the $1.9 million experienced in 1998. Berry acquired
certain properties in the Placerita field in Los Angeles County, California in
January of 1999. The financing of those properties resulted in higher interest
costs in 1999. The Company aggressively reduced its total debt from $52 million
at December 31, 1999 to just $25 million at December 31, 2000. This reduction,
partially offset by higher interest rates, resulted in the reduced interest
expense experienced in 2000 compared with 1999 results. In early 2001, the
Company increased its borrowing to $70 million to ensure liquidity during
this period of nonpayment for electricity deliveries by utilities and higher
natural gas prices, to pay an annual price-based royalty on one of its
properties and for other general purposes.
Even though the Company's pre-tax net income was up sharply in 2000 versus
1999 and 1998, the Company invested heavily in the development of its thermally
enhanced oil recovery (EOR) projects, both through capital expenditures and
increased steam injection volumes, thus, the Company earned significant EOR
tax credits. This is the third consecutive year that the Company has achieved
an effective tax rate below 30%, versus the statutory rate of 40%. The Company
believes it will continue to earn significant EOR tax credits in the future and
have an effective tax rate well below 40%.
Financial Condition, Liquidity and Capital Resources
During 2000, the Company aggressively reduced its long-term debt by $27
million. As a result, working capital at December 31, 2000 was negative $1.2
million, down from positive $8.4 million in 1999 and $9.1 million in 1998.
Net cash provided by operations was $65.9 million, a Company record and 166%
and 231% higher than $24.8 million in 1999 and $19.9 million in 1998. The
Company employed these resources to fund its $25.3 million capital program,
reduce debt by $27 million, pay dividends of $8.8 million and make a $3 million
acquisition.
Crude oil prices remain very attractive and, while the Company has
identified significant development opportunities, the Company intends to
postpone the majority of those projects until the Company can restart its
cogeneration facilities and inject that steam into the oil reservoirs. The
2001 budget focuses on further development of the Company's core properties
and development of certain underdeveloped portions of its Placerita area
properties. The Company has reduced its 2001 budget from its original $25
million to a current level of $11 million, which includes only essential
projects and profitable projects based upon current economic conditions.
The Company is pursuing adding additional cogeneration facilities to
fully develop its properties and replace its conventional steam generation
sources. As a generator of electricity, the Company is directly affected by
the well-publicized California electrical crisis. As of March 7, 2001, the
Company is owed a total of $25 million for electricity sales to Edison and
PG&E from November 2000 through February 2001. Management anticipates that
these amounts due will be paid in their entirety, however, the timing of the
payments is uncertain at this time. In addition, if the Company is unable to
collect a significant portion of these receivables, the write-off of such
portion may have an adverse effect on the financial position or results of
operations of the Company.
Impact of Inflation
The impact of inflation on the Company has not been significant in recent
years because of the relatively low rates of inflation experienced in the
United States.
18
Recent Accounting Developments
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Standard No. 133 "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). The statement requires the recognition
of all derivatives as either assets or liabilities in the balance sheet and the
measurement of those instruments at fair value. The accounting for changes in
the fair value of a derivative depends on the planned use of the derivative and
the resulting designation. The adoption of SFAS 133 in the fourth quarter
of 2000 did not have a significant impact on the Company's financial position,
results of operations or cash flows.
In December 1999, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 101, Revenue Recognition in Financial Statements
(SAB 101). SAB 101 provides guidance for revenue recognition under certain
circumstances. The adoption of SAB 101 in 2000 did not have a significant
impact on the Company's financial position, results of operations or cash flows.
In March 2000, the FASB, issued FASB Interpretation No. 44, (FIN 44),
Accounting for Certain Transactions Involving Stock Compensation an
Interpretation of APB Opinion No. 25. FIN 44 clarifies the application of
APB Opinion No. 25 for (a) the definition of employee for purposes of applying
APB Opinion No. 25, (b) the criteria for determining whether a plan qualifies
as a noncompensatory plan, (c) the accounting consequence of various
modifications to the terms of a previously fixed stock option or award, and
(d) the accounting for an exchange of stock compensation awards in a
business combination. FIN 44 became effective July 1, 2000, but certain
conclusions cover specific events that occur after either December 15, 1998
or January 12, 2000. The adoption of FIN 44 did not have a significant impact
on the Company's financial position, results of operations or cash flows.
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-K 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, SoCal border pricing for natural gas, pipeline capacity for
natural gas to and within California, the non-existence of a liquid
marketplace for electricity purchases and sales within California, competition,
environmental risks, litigation uncertainties, drilling, development and
operating risks, uncertainties about the estimates of reserves, the prices of
goods and services, the availability of drilling rigs and other support
services, legislative, California Public Utilities Commission, Federal Energy
Regulatory Commission, and/or judicial decisions and other government
regulations.
19
Item 8. Financial Statements and Supplementary Data
BERRY PETROLEUM COMPANY
Index to Financial Statements and
Supplementary Data
Page
Report of PricewaterhouseCoopers LLP, Independent Accountants 21
Balance Sheets at December 31, 2000 and 1999 22
Statements of Operations for the
Years Ended December 31, 2000, 1999 and 1998 23
Statements of Comprehensive Income for the
Years Ended December 31, 2000, 1999 and 1998 23
Statements of Shareholders' Equity for the
Years Ended December 31, 2000, 1999 and 1998 24
Statements of Cash Flows for the
Years Ended December 31, 2000, 1999 and 1998 25
Notes to the Financial Statements 26
Supplemental Information About Oil & Gas Producing Activities 38
Financial statement schedules have been omitted since they are either
not required, are not applicable, or the required information is shown in
the financial statements and related notes.
20
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors
Berry Petroleum Company
In our opinion, the accompanying balance sheets and the related statements of
operations and shareholders' equity and of cash flows present fairly, in all
material respects, the financial position of Berry Petroleum Company (the
"Company") at December 31, 2000 and 1999, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally
accepted in the United States of America. These financial statements are the
responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted
our audits of these statements in accordance with auditing standards generally
accepted in the United States of America which require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
/s/ PricewaterhouseCoopers LLP
March 9, 2001
Los Angeles, California
21
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 2000 and 1999
(In Thousands, Except Share Information)
2000 1999
ASSETS
Current assets:
Cash and cash equivalents $ 2,731 $ 980
Short-term investments available for sale 582 596
Accounts receivable 26,420 15,303
Prepaid expenses and other 5,190 2,080
-------- --------
Total current assets 34,923 18,959
Oil and gas properties (successful efforts basis),
buildings and equipment, net 201,643 186,519
Other assets 1,793 2,171
-------- --------
$ 238,359 $ 207,649
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 28,678 $ 7,203
Accrued liabilities 2,288 1,999
Federal and state income taxes payable 5,110 1,322
-------- --------
Total current liabilities 36,076 10,524
Long-term debt 25,000 52,000
Deferred income taxes 32,059 28,912
Commitments and contingencies (Note 9) - -
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; 21,134,667 shares issued and
outstanding (21,112,334 in 1999) 211 211
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 53,686 53,487
Accumulated other comprehensive income 441 -
Retained earnings 90,877 62,506
-------- --------
Total shareholders' equity 145,224 116,213
-------- --------
$ 238,359 $ 207,649
======== ========
The accompanying notes are an integral part of these financial statements.
22
BERRY PETROLEUM COMPANY
Statements of Operations
Years ended December 31, 2000, 1999 and 1998
(In Thousands, Except Per Share Data)
2000 1999 1998
Revenues:
Sales of oil and gas $ 118,801 $ 66,615 $ 39,858
Sales of electricity 52,765 33,731 15,680
Interest and dividend income 447 674 805
Other income (expense), net 36 186 (764)
-------- -------- --------
172,049 101,206 55,579
-------- -------- --------
Expenses:
Operating costs - oil and gas production 46,789 28,697 18,272
Operating costs - electricity generation 48,614 27,062 15,236
Depreciation, depletion & amortization 14,030 12,294 10,080
General and administrative 7,754 6,269 3,975
Interest expense 3,186 3,973 1,939
Impairment of properties - - 1,827
-------- -------- --------
120,373 78,295 51,329
-------- -------- --------
Income before income taxes 51,676 22,911 4,250
Provision for income taxes 14,493 4,905 371
-------- -------- --------
Net income $ 37,183 $ 18,006 $ 3,879
======== ======== ========
Basic net income per share $ 1.69 $ .82 $ .18
======== ======== ========
Diluted net income per share $ 1.67 $ .82 $ .18
======== ======== ========
Weighted average number of shares of
capital stock outstanding (used to
calculate basic net income per share) 22,029 22,010 22,007
Effect of dilutive securities:
Employee stock options 185 32 25
Other 26 7 5
-------- -------- --------
Weighted average number of shares
of capital stock used to calculate
diluted net income per share 22,240 22,049 22,037
======== ======== ========
Statements of Comprehensive Income
Years Ended December 31, 2000, 1999 and 1998
(In Thousands)
2000 1999 1998
Net income $ 37,183 $ 18,006 $ 3,879
Unrealized gains on derivatives 441 - -
-------- -------- --------
Other comprehensive income $ 37,624 $ 18,006 $ 3,879
======== ======== ========
The accompanying notes are an integral part of these financial statements.
23
BERRY PETROLEUM COMPANY
Statements of Shareholders' Equity
Years Ended December 31, 2000, 1999 and 1998
(In Thousands, Except Per Share Data)
Accumulated
Capital in Other
Excess of Retained Comprehensive Shareholders
Class A Class B Par Value Earnings Income Equity
Balances at January 1, 1998 $ 211 $ 9 $ 53,422 $ 58,229 $ - $ 111,871
Stock options exercised - - (58) - - (58)
Deferred director fees -
stock compensation - - 36 - - 36
Cash dividends declared -
$.40 per share - - - (8,804) - (8,804)
Net income - - - 3,879 - 3,879
----- ----- ------- ------- ------ --------
Balances at December 31, 1998 211 9 53,400 53,304 - 106,924
Stock options exercised - - 2 - - 2
Deferred director fees - stock
compensation - - 85 - - 85
Cash dividends declared -
$.40 per share - - - (8,804) - (8,804)
Net income - - - 18,006 - 18,006
----- ----- ------- ------- ------ --------
Balances at December 31, 1999 211 9 53,487 62,506 - 116,213
Stock options exercised - - 90 - - 90
Deferred director fees - stock
compensation - - 109 - - 109
Cash dividends declared -
$.40 per share - - - (8,812) - (8,812)
Unrealized gains on derivatives - - - - 441 441
Net income - - - 37,183 - 37,183
----- ----- ------- ------- ------ --------
Balances at December 31, 2000 $ 211 $ 9 $ 53,686 $ 90,877 $ 441 $ 145,224
===== ===== ======= ======= ====== ========
The accompanying notes are an integral part of these financial statements.
24
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 2000, 1999 and 1998
(In Thousands)
2000 1999 1998
Cash flows from operating activities:
Net income $ 37,183 $ 18,006 $ 3,879
Depreciation, depletion and amortization 14,030 12,294 10,080
Impairment of properties - - 1,827
Increase in deferred income tax liability 3,147 263 2,740
Other, net 249 (208) (315)
------- ------- -------
Net working capital provided by
operating activities 54,609 30,355 18,211
Decrease (increase) in current assets
other than cash, cash equivalents and
short-term investments (14,227) (7,839) 1,425
Increase in current liabilities other
than notes payable 25,552 2,293 288
------- ------- -------
Net cash provided by operating activities 65,934 24,809 19,924
------- ------- -------
Cash flows from investing activities:
Capital expenditures, excluding
property acquisitions (25,253) (9,122) (6,981)
Property/facility acquisitions (3,182) (33,605) (2,991)
Proceeds from sale of assets 49 21 350
Purchase of short-term investments (584) (611) -
Maturities of short-term investments 600 725 8
Contract purchases - (1,028) (240)
------- ------- -------
Net cash used in investing activities (28,370) (43,620) (9,854)
------- ------- -------
Cash flows from financing activities:
Proceeds from issuance of long-term debt 1,000 35,000 -
Payment of long-term debt (28,000) (13,000) (2,000)
Dividends paid (8,812) (8,804) (8,804)
Other, net (1) (463) 36
------- ------- -------
Net cash provided by (used in)
financing activities (35,813) 12,733 (10,768)
------- ------- -------
Net increase (decrease) in cash
and cash equivalents 1,751 (6,078) (698)
Cash and cash equivalents at
beginning of year 980 7,058 7,756
------- ------- -------
Cash and cash equivalents at end of year $ 2,731 $ 980 $ 7,058
======= ======= =======
Supplemental disclosures of cash
flow information:
Interest paid $ 2,999 $ 4,546 $ 1,924
======= ======= =======
Income taxes paid $ 9,712 $ 4,079 $ 270
======= ======= =======
The accompanying notes are an integral part of these financial statements.
25
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
1. General
The Company is an independent energy company engaged in the production,
development, acquisition, exploitation and exploration of crude oil and natural
gas. Substantially all of the Company's oil and gas reserves are located in
California. Approximately 99% of the Company's production is heavy crude oil,
which is principally sold to other oil companies for processing in refineries
located in California. The Company has invested in cogeneration facilities
which provides steam required for the extraction of heavy oil and which
generates electricity for sale.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
Management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from
those estimates.
2. Summary of Significant Accounting Policies
Cash and cash equivalents
The Company considers all highly liquid investments purchased with a
remaining maturity of three months or less to be cash equivalents.
Short-term investments
All short-term investments are classified as available for sale.
Short-term investments consist principally of United States treasury notes
and corporate notes with remaining maturities of more than three months at
date of acquisition. Such investments are stated at cost, which approximates
market. The Company utilizes specific identification in computing realized
gains and losses on investments sold.
Oil and gas properties, buildings and equipment
The Company accounts for its oil and gas exploration and development costs
using the successful efforts method. Under this method, costs to acquire and
develop proved reserves and to drill and complete exploratory wells that find
proved reserves are capitalized and depleted over the remaining life of the
reserves using the units-of-production method. Exploratory dry hole costs
and other exploratory costs, including geological and geophysical costs, are
charged to expense when incurred. The costs of carrying and retaining
unproved properties are also expensed when incurred.
Depletion of oil and gas producing properties is computed using the
units-of-production method. Depreciation of lease and well equipment,
including cogeneration facilities and other steam generation equipment and
facilities, is computed using the units-of-production method or on a
straight-line basis over estimated useful lives ranging from 10 to 20 years.
The estimated costs, net of salvage value, of plugging and abandoning oil and
gas wells and related facilities are accrued using the units-of-production
method and are taken into account in determining DD&A expense. Buildings and
equipment are recorded at cost. Depreciation is provided on a straight-line
basis over estimated useful lives ranging from 5 to 30 years for buildings
and improvements and 3 to 10 years for machinery and equipment. Assets are
grouped at the field level and if it is determined that the book value of
long-lived assets cannot be recovered by estimated future undiscounted cash
flows, they are written down to fair value. When assets are sold, the
applicable costs and accumulated depreciation and depletion are removed from
the accounts and any gain or loss is included in income. Expenditures for
maintenance and repairs are expensed as incurred.
26
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (cont'd)
Hedging
From time to time, the Company utilizes options, swaps and collars
(derivative instruments) to manage its commodity price risk. On October 1,
2000 , the Company adopted Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133) which established new accounting and reporting requirements for
derivative instruments and hedging activities. SFAS 133 requires that all
derivative instruments subject to the requirements of the statement be
measured at fair value and recognized as assets or liabilities in the
balance sheet. The accounting for changes in the fair value of a derivative
depends on the intended use of the derivative and the resulting designation.
For derivatives designated as cash flow hedges and meeting the effectiveness
guidelines of SFAS 133, changes in fair value, to the extent effective, are
recognized in other comprehensive income until the hedged item is recognized
in earnings. Hedge effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract and the hedged
item over time, or in the case of options based on the change in intrinsic
value. Any change in fair value of a derivative resulting from ineffectiveness
or an excluded component of the gain/loss, such as time value for option
contracts, is recognized immediately as operating costs in the statement of
operations.
Upon adoption, the Company determined that it had contracts related to
the long-term sale of crude oil and electricity that met the definition of a
derivative under SFAS 133. However, these derivative instruments are
considered normal sales under provisions of SFAS 133 and are, therefore,
specifically exempt from the accounting and disclosures detailed above. At
December 31, 2000, all of the Company's SFAS 133 derivative instruments were
either exempt from the standard or designated as cash flow hedges and no
amounts were reclassified into earnings as a result of the discontinuance of
cash flow hedges because it was determined that the original forecasted
transaction was no longer probable. See Note 3 - Fair Value of Financial
Instruments.
Cogeneration Operations
The Company operates cogeneration facilities to help minimize the cost of
producing steam, which is a necessity in its thermal oil and gas producing
operations. Such cogeneration operations produce electricity as a by-product
from the production of steam. In prior years, amounts billed for the sale of
electricity were reported as a reduction to operating costs in the Company's
financial statements. In 2000, the Company modified its financial statement
presentation. These amounts are now reported as revenues from the sale of
electricity. The Company has considered allocating the cost of operating
the cogeneration plants between those costs incurred in producing steam and
those in producing electricity, but determined any such allocation to be
arbitrary and not meaningful to financial statement presentation. Therefore,
in each monthly accounting period, the cost of operating the cogeneration
facilities in each field of operation, up to the amount of the electricity
sales, is considered operating costs from electricity generation. Costs in
excess of electricity revenue during each period, if any, are considered cost
of producing steam and are reported in operating costs - oil and gas
production.
Conventional Steam Costs
The costs of producing conventional steam are included in operating
costs - oil and gas production.
Revenue Recognition
Revenues associated with sales of crude oil, natural gas, and electricity
are recorded when title passes to the customer, net of royalties, discounts
and allowances, as applicable. Revenues from crude oil and natural gas
production from properties in which the Company has an interest with other
producers are recognized on the basis of the Company's net working interest
(entitlement method).
27
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (cont'd)
Stock-Based Compensation
As allowed in SFAS 123, "Accounting for Stock-Based Compensation", the
Company continues to apply Accounting Principles Board Opinion (APB) No. 25,
"Accounting for Stock Issued to Employees," and related interpretations in
recording compensation related to its plans. The supplemental disclosure
requirements of SFAS 123 and further information related to the Company's
stock option plans are presented in Note 10 to the Company's financial
statements.
Income Taxes
Income taxes are provided based on the liability method of accounting.
The provision for income taxes is based on pre-tax financial accounting income.
Deferred tax assets and liabilities are recognized for the future expected tax
consequences of temporary differences between income tax and financial
reporting, and principally relate to differences in the tax basis of assets
and liabilities and their reported amounts using enacted tax rates in effect
for the year in which differences are expected to reverse. If it is more
likely than not that some portion or all of a deferred tax asset will not be
realized, a valuation allowance is recognized.
Net Income Per Share
Basic net income per share is computed by dividing income available to
common shareholders (the numerator) by the weighted average number of common
shares outstanding (the denominator). The computation of diluted net income
per share is similar to the computation of basic net income per share except
that the denominator is increased to include the dilutive effect of the
additional common shares that would have been outstanding if all convertible
securities had been converted to common shares during the period.
Recent Accounting Developments
In June 1998, the Financial Accounting Standards Board (FASB) issued
SFAS 133 "Accounting for Derivative Instruments and Hedging Activities". The
statement requires the recognition of all derivatives as either assets or
liabilities in the balance sheet and the measurement of those instruments at
fair value. The accounting for changes in the fair value of a derivative
depends on the planned use of the derivative and the resulting designation.
The adoption of SFAS 133 in the fourth quarter of 2000 did not have a
significant impact on the Company's financial position, results of operations
or cash flows.
In December 1999, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 101, Revenue Recognition in Financial Statements
(SAB 101). SAB 101 provides guidance for revenue recognition under certain
circumstances. The adoption of SAB 101 in 2000 did not have a significant
impact on the Company's financial position, results of operations or cash
flows.
In March 2000, the FASB, issued FASB Interpretation No. 44, (FIN 44),
Accounting for Certain Transactions Involving Stock Compensation an
Interpretation of APB Opinion No. 25. FIN 44 clarifies the application of
APB Opinion No. 25 for (a) the definition of employee for purposes of applying
APB Opinion No. 25, (b) the criteria for determining whether a plan qualifies
as a noncompensatory plan, (c) the accounting consequence of various
modifications to the terms of a previously fixed stock option or award, and
(d) the accounting for an exchange of stock compensation awards in a
business combination. FIN 44 became effective July 1, 2000, but certain
conclusions cover specific events that occur after either December 15, 1998
or January 12, 2000. The adoption of FIN 44 did not have a significant
impact on the Company's financial position, results of operations or cash
flows.
28
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
Summary of Significant Accounting Policies (cont'd)
Reclassifications
Certain reclassifications have been made to the 1999 and 1998 financial
statements to conform with the 2000 presentation.
3. Fair Value of Financial Instruments
The carrying amounts of cash and short-term investments are not materially
different from their fair values because of the short maturity of those
instruments. Cash equivalents consist principally of commercial paper
investments. Cash equivalents of $2.3 million and $.2 million at
December 31, 2000 and 1999, respectively, are stated at cost, which
approximates market.
The Company's short-term investments available for sale at December 31,
2000 and 1999 consist of a United States treasury note that matures in less
than one year. The carrying value of the Company's long-term debt is assumed
to approximate its fair value since it is carried at current interest rates.
For the three years ended December 31, 2000, realized and unrealized gains
and losses were insignificant to the financial statements. A United States
treasury note with a market value of $.6 million is pledged as collateral to
the California State Lands Commission as a performance bond on the Company's
Montalvo properties.
To protect the Company's revenues from potential price declines, the
Company entered into bracketed zero cost collar hedge contracts with California
refiners covering 3,000 BPD to 6,500 BPD of its crude oil production during
1998, 1999 and 2000. The posted price of the Company's 13 degree API gravity
crude oil was used as the basis for the hedge. The most recent contracts
expired on December 31, 2000. Gains and losses from these cash flow hedges are
reported in revenues from oil and gas producing operations in the Company's
financial statements. The Company recorded losses of $7.1 million and
$2.6 million in 2000 and 1999, respectively, and a gain of $2.2 million
during 1998. At the present time, the Company has no plans to enter into
similar contracts, but may do so in the future if deemed appropriate as
market conditions change.
In December 2000, the Company entered into a series of derivative
contracts to reduce exposure to unfavorable changes in natural gas prices.
These contracts limit the price the Company pays for 4,500 Mmbtu/day of
natural gas used by its cogeneration facilities for the three month period
ending March 31, 2001. During December 2000, the Company recorded an expense
of $.3 million related to the ineffective portion of these derivative
instruments and, at the end of the year, recorded $.4 million in other
comprehensive income, after-tax, related to unrealized gains on derivatives.
29
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
4. Concentration of Credit Risks
The Company sells oil, gas and natural gas liquids to pipelines,
refineries and major oil companies and electricity to major utility companies.
Credit is extended based on an evaluation of the customer's financial
condition and historical payment record. For the three years ended
December 31, 2000, the Company has experienced no credit losses on the sale
of oil, gas, natural gas liquids, electricity or derivatives instruments.
However, the Company has not been fully paid for certain electricity sales
that occurred in late 2000, see Note 9.
The Company places its temporary cash investments with high quality
financial institutions and limits the amount of credit exposure to any one
financial institution. For the three years ended December 31, 2000, the
Company has not incurred losses related to these investments.
The following summarizes the accounts receivable balances at December 31,
2000 and 1999 and sales activity with significant customers for each of the
years ended December 31, 2000, 1999 and 1998 (in thousands):
Sales
Accounts Receivable For the Year Ended December 31,
Customer Dec. 31, 2000 Dec. 31, 1999 2000 1999 1998
Oil & Gas
Sales:
A $ 9,699 $ 3,975 $ 87,613 $ 30,289 $ 12,409
B 1,246 1,312 18,000 6,262 2,187
C - 1,627 13,080 11,467 7,281
D 24 2,040 12,390 15,064 6,282
E 391 406 5,499 7,890 10,785
------ ------ ------- ------- -------
$ 11,360 $ 9,360 $ 136,582 $ 70,972 $ 38,944
====== ====== ======= ======= =======
Electricity Sales:
F $ 8,660 $ 3,141 $ 26,769 $ 15,603 $ 15,624
G 5,625 2,034 23,124 16,013 -
------ ------ ------- ------- -------
$ 14,285 $ 5,175 $ 49,893 $ 31,616 $ 15,624
====== ====== ======= ======= =======
30
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
5. Oil and Gas Properties, Buildings and Equipment
Oil and gas properties, buildings and equipment consist of the following
at December 31 (in thousands):
2000 1999
Oil and gas:
Proved properties:
Producing properties, including
intangible drilling costs $ 160,484 $ 146,616
Lease and well equipment 138,007 123,026
-------- --------
298,491 269,642
Less accumulated depreciation,
depletion and amortization 98,925 85,319
-------- --------
199,566 184,323
-------- --------
Commercial and other:
Land 173 170
Buildings and improvements 4,086 4,072
Machinery and equipment 4,553 4,211
-------- --------
8,812 8,453
Less accumulated depreciation 6,735 6,257
-------- --------
2,077 2,196
-------- --------
$ 201,643 $ 186,519
======== ========
The following sets forth costs incurred for oil and gas property acquisition
and development activities, whether capitalized or expensed (in thousands):
2000 1999 1998
Acquisition of properties/
facilities(1) $ 3,204 $ 34,167 $ 2,991
Development 26,145 9,195 6,896
-------- -------- --------
$ 29,349 $ 43,362 $ 9,887
======== ======== ========
(1) Includes cogeneration facility costs and certain closing and consultant
costs related to the acquisitions, but excluding electricity contract costs.
In 2000, the Company purchased the Castruccio property at the Placerita
field for approximately $3 million, and the property has approximately
1.5 million barrels of proved reserves at year-end. In 1999, the Company
completed the Placerita acquisition for a purchase price of approximately
$35 million, including the purchase of a 42 megawatt cogeneration facility
and related electricity contracts. These properties had proved reserves of
approximately 20 million barrels upon acquisition. In 1998, the Company
completed an acquisition with proved reserves of approximately 1 million
barrels and a steam contract located adjacent to the Company's core South
Midway-Sunset producing properties.
31
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
5. Oil and Gas Properties, Buildings and Equipment (cont'd)
Results of operations from oil and gas producing and exploration activities
The results of operations from oil and gas producing and exploration
activities (excluding corporate overhead and interest costs) for the three
years ended December 31 are as follows (in thousands):
2000 1999 1998
Sales to unaffiliated parties $ 118,801 $ 66,615 $ 39,858
Production costs (46,789) (28,697) (18,272)
Depreciation, depletion and amortization (13,712) (12,020) (9,686)
-------- -------- --------
58,300 25,898 11,900
Income tax expenses (17,292) (5,856) (3,026)
-------- -------- --------
Results of operations from producing and
exploration activities $ 41,008 $ 20,042 $ 8,874
======== ======== ========
6. Debt Obligations
2000 1999
Long-term debt for the years ended December 31
(in thousands):
Revolving bank facility $ 25,000 $ 52,000
======== ========
On July 22, 1999, the Company executed an Amended and Restated Credit
Agreement (the Agreement) with a banking group, which consists of four banks,
for a $150 million five-year unsecured bullet loan. At December 31, 2000 and
1999, the Company had $25 and $52 million, respectively, outstanding under
the Agreement. Subsequent to year end 2000, the Company increased its
borrowings to $70 million to be utilized for general corporate purposes.
The maximum amount available is subject to an annual redetermination of the
borrowing base in accordance with the lender's customary procedures and
practices. Both the Company and the banks have bilateral rights to one
additional redetermination each year. The revolving period is scheduled to
terminate on January 21, 2004. Interest on amounts borrowed is charged at the
lead bank's base rate or at London Interbank Offered Rates (LIBOR) plus 75
to 150 basis points, depending on the ratio of outstanding credit to the
borrowing base. The weighted average interest rate on outstanding borrowings
at December 31, 2000 was 7.43%. The Company pays a commitment fee of 25 to 35
basis points on the available unused portion of the commitment. The credit
agreement contains other restrictive covenants as defined in the Agreement.
Previously, on January 21, 1999, the Company amended its existing credit
agreement with its lead bank primarily to increase the borrowing base to
$110 million and add two additional banks to its syndication.
7. Shareholders' Equity
Shares of Class A Common Stock (Common Stock) and Class B Stock, referred
to collectively as the "Capital Stock," are each entitled to one vote and 95%
of one vote, respectively. Each share of Class B Stock is entitled to a $1.00
per share preference in the event of liquidation or dissolution. Further, each
share of Class B Stock is convertible into one share of Common Stock at the
option of the holder.
32
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
7. Shareholders' Equity (cont'd)
In November 1999, the Company adopted a Shareholder Rights Agreement and
declared a dividend distribution of one Right for each outstanding share of
Capital Stock on December 8, 1999. Each Right, when exercisable, entitles
the holder to purchase one one-hundredth of a share of a Series B Junior
Participating Preferred Stock, or in certain cases other securities, for
$38.00. The exercise price and number of shares issuable are subject to
adjustment to prevent dilution. The Rights would become exercisable, unless
earlier redeemed by the Company, 10 days following a public announcement that
a person or group has acquired, or obtained the right to acquire, 20% or more
of the outstanding shares of Common Stock or, 10 business days following the
commencement of a tender or exchange offer for such outstanding shares which
would result in such person or group acquiring 20% or more of the outstanding
shares of Common Stock, either event occurring without the prior consent of
the Company.
The Rights will expire on December 8, 2009 or may be redeemed by the
Company at $.01 per Right prior to that date unless they have theretofore
become exercisable. The Rights do not have voting or dividend rights, and
until they become exercisable, have no diluting effect on the earnings of the
Company. A total of 250,000 shares of the Company's Preferred Stock has been
designated Series B Junior Participating Preferred Stock and reserved for
issuance upon exercise of the Rights. This Shareholder Rights Agreement
replaces the Shareholder Rights Agreement approved in December 1989 which
expired on December 8, 1999.
In conjunction with the acquisition of the Tannehill assets in 1996, the
Company issued a Warrant Certificate to the beneficial owners of Tannehill Oil
Company. This Warrant authorizes the purchase of 100,000 shares of Berry
Petroleum Company Class A Common Stock until November 8, 2003 at $14.06 per
share. All the warrants are currently outstanding and the underlying shares
will not be registered under the Securities Act of 1933.
The Company issued 21,325, 2,745 and 15,268 shares in 2000, 1999 and 1998,
respectively, through its stock option plan.
At December 31, 2000, dividends declared on 4,000,894 shares of certain
Common Stock are restricted, whereby 37.5% of the dividends declared on these
shares are paid by the Company to the surviving member of a group of
individuals, the B Group, as long as this remaining member shall live.
8. Income Taxes
The Provision for income taxes consists of the following (in thousands):
2000 1999 1998
Current:
Federal $ 10,336 $ 2,661 $ (716)
State 3,165 928 (881)
------- ------- -------
13,501 3,589 (1,597)
------- ------- -------
Deferred:
Federal 1,787 1,979 1,968
State (795) (663) -
------- ------- -------
992 1,316 1,968
------- ------- -------
Total $ 14,493 $ 4,905 $ 371
======= ======== =======
33
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
8. Income Taxes (cont'd)
The current deferred tax assets and liabilities are offset and presented
as a single amount in the financial statements. Similarly, the noncurrent
deferred tax assets and liabilities are presented in the same manner. The
following table summarizes the components of the total deferred tax assets
and liabilities before such financial statement offsets. The components of
the net deferred tax liability consist of the following at December 31
(in thousands):
2000 1999 1998
Deferred tax asset
Federal benefit of state taxes $ 871 $ 392 $ -
Credit/deduction carryforwards 7,761 4,434 2,602
Other, net 1,261 367 322
------- ------- -------
9,893 5,193 2,924
------- ------- -------
Deferred tax liability
Depreciation and depletion (39,894) (33,452) (29,806)
Other, net 246 (504) (565)
------- ------- -------
(39,648) (33,956) (30,371)
------- ------- -------
Net deferred tax liability $ (29,755) $ (28,763) $ (27,447)
======= ======= =======
Reconciliation of the statutory federal income tax rate to the effective income
tax rate follows:
2000 1999 1998
Tax computed at statutory federal rate 35.0% 35.0% 34.0%
State income taxes, net of federal benefit 3.4 .3 2.0
Tax credits (11.0) (12.9) (24.3)
Other .7 (1.0) (3.0)
----- ----- -----
Effective tax rate 28.1% 21.4% 8.7%
===== ===== =====
The Company has approximately $6.1 million of federal and $4.5 million of
state enhanced oil recovery (EOR) tax credit carryforwards available to reduce
future income taxes. EOR credits of $7.9 million and $2.7 million will expire
in 2014 and 2015, respectively.
34
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Contingency
The Company has been severely impacted by the current electricity crisis
that exists in California. As of December 31, 2000, the Company was owed a
total of $14.3 million from Southern California Edison Company (Edison) and
Pacific Gas & Electric Company (PG&E), which represented amounts due for the
sale of electricity from November and December 2000. Since year-end, the
Company has received $3.2 million, of this amount, from PG&E, thus payments for
a total of $11.1 million remain outstanding related to November and December
deliveries. A total of $13.8 million is also due for January and February 2001
deliveries, resulting in a total receivable at March 9, 2001 of $25 million;
$12.1 million and $12.9 million from PG&E and Edison, respectively. The
Company shut down the majority of its cogeneration operations during
February 2001 as a result of this situation and expects its receivable for
March power deliveries to be approximately $2 million. The Company
anticipates that this situation will be resolved, these receivables will be
paid in full and the Company will return to normal operations. However, the
Company cannot estimate the timing when this will occur. In addition, if the
Company is unable to collect a significant portion of these receivables, the
write-off of such portion may have a material adverse effect on the financial
position or results of operations of the Company.
10. Stock Option Plan
On December 2, 1994, the Board of Directors of the Company adopted the
Berry Petroleum Company 1994 Stock Option Plan which was restated and amended
in December 1997 (the 1994 Plan) and approved by the shareholders in May 1998.
The 1994 Plan provides for the granting of stock options to purchase up to an
aggregate of 2,000,000 shares of Common Stock. All options, with the
exception of the formula grants to non-employee Directors, will be granted
at the discretion of the Compensation Committee of the Board of Directors.
The term of each option may not exceed ten years from the date the option is
granted.
On December 1, 2000 and December 4, 1998, 262,000 and 434,000 options,
respectively, were issued to certain key employees at an exercise price of
$15.6875 and $12.50, per share, respectively, which was the closing market
price of the Company's Class A Common Stock on the New York Stock Exchange
on those dates. The options vest 25% per year for four years. No employee
options were issued in 1999. The 1994 Plan also allows for option grants to
the Board of Directors under a formula plan whereby all non-employee Directors
are eligible to receive 5,000 options annually on December 2 at the fair
value on the date of grant. The options granted to the non-employee Directors
vest immediately. Through the 1994 Plan, 40,000, 40,000 and 45,000 options,
respectively, were issued on December 2, 2000, 1999 and 1998, (5,000 options
to each of the non-employee Directors each year) at an exercise price of
$15.6875, $14.0625 and $12.625 per share, respectively. In addition, 25,000
options were granted on May 15, 1998 to the non-employee Directors on
December 2, 1997, at an exercise price of $18.9375.
The Company applies APB No. 25 and related interpretations in accounting
for its stock option plan. The options issued per the 1994 Plan were issued
at market price. Compensation recognized related to the 1994 Plan was $.3
million in 2000, $0 in 1999 and $.4 million in 1998.
Under SFAS 123, compensation cost would be recognized for the fair
value of the employee's option rights. The fair value of each option grant
was estimated on the date of grant using the Black-Scholes option-pricing
model with the following assumptions:
2000 1999 1998
Yield 2.77% 2.75% 2.87%
Expected option life - years 4.5 4.0 4.0
Volatility 36.53% 34.24% 28.13%
Risk-free interest rate 4.85% 6.33% 4.68%
35
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. Stock Option Plan (cont'd)
Had compensation cost for the 1994 Plan been based upon the fair value at
the grant dates for awards under this plan consistent with the method of SFAS
No. 123, the Company's net income and earnings per share would have been
reduced to the pro forma amounts indicated below (in thousands, except per
share data):
2000 1999 1998
Net income as reported $ 37,183 $ 18,006 $ 3,879
Pro forma 36,581 17,343 3,244
Net income per share as reported 1.69 .82 .18
Pro forma 1.66 .79 .15
The following is a summary of stock-based compensation activity for the years
2000, 1999 and 1998.
2000 1999 1998
Options Options Options SARs
--------- --------- --------- ------
Balance outstanding, January 1 1,220,630 1,227,630 924,429 1,120
Granted 302,000 40,000 504,000 -
Exercised (114,793) (22,000) (75,799) (1,120)
Canceled/expired - (25,000) (125,000) -
--------- --------- --------- ------
Balance outstanding, December 31 1,407,837 1,220,630 1,227,630 -
========= ========= ========= ======
Balance exercisable at
December 31 872,587 697,630 449,880 -
========= ========= ========= ======
Available for future grant 364,800 666,800 681,800 -
========= ========= ========= ======
Exercise price-range $ 16.4375 $ 14.125 $ 9.80 $ 9.80
to 19.00 to 14.25 to 19.375
Weighted average remaining
contractual life (years) 8 8 9 -
Weighted average fair value
per option granted during
the year $ 4.62 $ 5.14 $ 2.82 N/A
36
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. Stock Option Plan (cont'd)
Weighted average option exercise price information for the years 2000, 1999
and 1998 as follows:
2000 1999 1998
Outstanding at January 1 $ 14.15 $ 14.18 $ 14.71
Granted during the year 15.69 14.06 12.83
Exercised during the year 12.91 12.40 11.42
Expired during the year - 16.69 14.34
Outstanding at December 31 14.58 14.15 14.18
Exercisable at December 31 14.50 14.21 14.17
11. Retirement Plan
The Company sponsors a defined contribution retirement or thrift plan
(401(k) Plan) to assist all employees in providing for retirement or other
future financial needs. Employee contributions (up to 6% of earnings) are
matched by the Company dollar for dollar. Effective November 1, 1992, the
401(k) Plan was modified to provide for increased Company matching of
employee contributions whereby the monthly Company matching contributions
will range from 6% to 9% of eligible participating employee earnings, if
certain financial targets are achieved. The Company's contributions to the
401(k) Plan were $.5 million in 2000, $.3 million in 1999 and $.2 million in
1998.
12. Quarterly Financial Data (unaudited)
The following is a tabulation of unaudited quarterly operating results for
2000 and 1999 (in thousands, except per share data):
Basic Net Diluted Net
Operating Gross Net Income Income
2000 Revenues Profit Income Per Share Per Share
First Quarter $ 35,136 $ 16,069 $ 8,859 $ .40 $ .40
Second Quarter 36,446 14,886 8,894 .40 .40
Third Quarter 45,939 15,096 9,578 .43 .43
Fourth Quarter 54,045 16,403 9,852 .45 .44
-------- -------- ------- ------ ------
$ 171,566 $ 62,454 $ 37,183 $ 1.69 $ 1.67
======== ======== ======= ====== ======
1999
First Quarter $ 17,054 $ 1,985 $ 544 $ .02 $ .02
Second Quarter 21,804 6,405 3,247 .15 .15
Third Quarter 27,879 10,232 6,099 .28 .28
Fourth Quarter 33,609 13,944 8,116 .37 .37
-------- -------- ------- ------ ------
$ 100,346 $ 32,566 $ 18,006 $ .82 $ .82
======== ======== ======= ====== ======
37
BERRY PETROLEUM COMPANY
Supplemental Information About Oil & Gas Producing Activities (Unaudited)
The following estimates of proved oil and gas reserves, both developed and
undeveloped, represent interests owned by the Company located solely within
the United States. Proved reserves represent estimated quantities of crude
oil and natural gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed oil and
gas reserves are the quantities expected to be recovered through existing
wells with existing equipment and operating methods. Proved undeveloped oil
and gas reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells for which relatively major
expenditures are required for completion.
Disclosures of oil and gas reserves which follow are based on estimates
prepared by independent engineering consultants as of December 31, 2000, 1999
and 1998. Such estimates are subject to numerous uncertainties inherent in
the estimation of quantities of proved reserves and in the projection of
future rates of production and the timing of development expenditures. These
estimates do not include probable or possible reserves. The information
provided does not represent Management's estimate of the Company's expected
future cash flows or value of proved oil and gas reserves.
Changes in estimated reserve quantities
The net interest in estimated quantities of proved developed and
undeveloped reserves of crude oil and natural gas at December 31, 2000, 1999
and 1998, and changes in such quantities during each of the years then ended
were as follows (in thousands):
2000 1999 1998
Oil Gas Oil Gas Oil Gas
Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf
Proved developed and
undeveloped reserves:
Beginning of year 111,888 3,920 91,933 4,060 100,454 3,531
Revision of previous
estimates (1,284) 463 3,126 40 (4,894) 774
Production (5,434) (199) (5,060) (180) (4,359) (245)
Purchase of reserves
in place 1,494 - 21,889 - 732 -
------- ------ ------- ------ ------- ------
End of year 106,664 4,184 111,888 3,920 91,933 4,060
======= ====== ======= ====== ======= ======
Proved developed reserves:
Beginning of year 86,717 1,371 83,532 1,604 86,858 1,457
======= ====== ======= ====== ======= ======
End of year 81,132 1,635 86,717 1,371 83,532 1,604
======= ====== ======= ====== ======= ======
38
BERRY PETROLEUM COMPANY
Supplemental Information About Oil & Gas Producing Activities (Unaudited)
(Cont'd)
The standardized measure has been prepared assuming year end sales prices
adjusted for fixed and determinable contractual price changes, current costs
and statutory tax rates (adjusted for tax credits and other items), and a ten
percent annual discount rate. No deduction has been made for depletion,
depreciation or any indirect costs such as general corporate overhead or
interest expense.
Standardized measure of discounted future net cash flows from estimated
production of proved oil and gas reserves (in thousands):
2000 1999 1998
Future cash inflows $ 2,268,932 $ 2,208,964 $ 656,607
Future production and
development costs (653,808) (647,720) (388,546)
Future income tax expenses (512,012) (502,951) (33,577)
--------- --------- ---------
Future net cash flows 1,103,112 1,058,293 234,484
10% annual discount for estimated timing
of cash flows (599,530) (561,811) (127,967)
--------- --------- ---------
Standardized measure of discounted future
net cash flows $ 503,582 $ 496,482 $ 106,517
========= ========= =========
Pre-tax standardized measure of discounted
future net cash flows $ 721,770 $ 714,555 $ 113,811
========= ========= =========
Average sales prices at December 31:
Oil ($/bbl) $ 20.63 $ 19.41 $ 7.05
Gas ($/mcf) $ 10.94 $ 2.11 $ 2.10
Changes in standardized measure of discounted future net cash flows from proved
oil and gas reserves (in thousands):
2000 1999 1998
Standardized measure - beginning
of year $ 496,482 $ 106,517 $ 267,594
--------- --------- ---------
Sales of oil and gas produced,
net of production costs (72,358) (44,587) (22,030)
Revisions to estimates of
proved reserves:
Net changes in sales prices
and production costs 98,744 440,729 (216,265)
Revisions of previous
quantity estimates (9,295) 20,919 (8,400)
Change in estimated future
development costs (78,328) (24,709) (17,262)
Purchases of reserves in place 14,135 169,147 1,597
Development costs incurred
during the period 25,253 9,122 6,728
Accretion of discount 71,455 11,381 37,539
Income taxes (3,929) (203,514) 46,293
Other (38,577) 11,477 10,723
--------- --------- ---------
Net increase (decrease) 7,100 389,965 (161,077)
--------- --------- ---------
Standardized measure - end of year $ 503,582 $ 496,482 $ 106,517
========= ========= ========
39
BERRY PETROLEUM COMPANY
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
The information called for by Item 10 is incorporated by reference from
information under the caption "Election of Directors" in the Company's
definitive proxy statement to be filed pursuant to Regulation 14A no later
than 120 days after the close of its fiscal year. The information on
Executive Officers is contained in Part I of this Form 10-K.
Item 11. Executive Compensation
The information called for by Item 11 is incorporated by reference from
information under the caption "Executive Compensation" in the Company's
definitive proxy statement to be filed pursuant to Regulation 14A no later
than 120 days after the close of its fiscal year.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information called for by Item 12 is incorporated by reference from
information under the captions "Security Ownership of Directors and Management"
and "Principal Shareholders" in the Company's definitive proxy statement to be
filed pursuant to Regulation 14A no later than 120 days after the close of
its fiscal year.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934 and related Securities
and Exchange Commission rules require that Directors and Executive Officers
report to the Securities and Exchange Commission changes in their beneficial
ownership of Berry stock, and that any late filings be disclosed. Based
solely on a review of the copies of such forms furnished to the Company, or
written representations that no Form 5 was required, the Company believes
that all Section 16(a) filing requirements were complied with, except that
two reports were filed late by Mr. Berry and one report was filed late by
Mr. Starzer in 2000.
Item 13. Certain Relationships and Related Transactions
The information called for by Item 13 is incorporated by reference from
information under the caption "Certain Relationships and Related Transactions"
in the Company's definitive proxy statement to be filed pursuant to Regulation
14A no later than 120 days after the close of its fiscal year.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
A. Financial Statements and Schedules
See Index to Financial Statements and Supplementary Data in Item 8.
40
BERRY PETROLEUM COMPANY
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(cont'd)
B. Reports on Form 8-K
On January 24, 2001, the Company filed a Form 8-K reporting an
Item 5. Other Event to disclose the fact that Southern California Edison was
delinquent in paying the Company for November 2000 electricity sales and that
Pacific Gas & Electric Company anticipated that its financial circumstances
would not allow it to pay for its December power purchases from the Company.
In addition, the filing disclosed the Company's electricity accounts
receivables position, its cogeneration contracts and the potential effect
the high natural gas prices were having on the cogeneration plants and the
Company's operations.
C. Exhibits
Exhibit No. Description of Exhibit Page
3.1* Registrant's Restated Certificate of Incorporation
(filed as Exhibit 3.1 to the Registrant's Registration
Statement on Form S-1 filed on June 7, 1989, File No.
33-29165)
3.2* Registrant's Restated Bylaws (filed as Exhibit 3.2 to
the Registrant's Registration Statement on Form S-1 on
June 7, 1989, File No. 33-29165)
3.3* Registrant's Certificate of Designation, Preferences
and Rights of Series B Junior Participating Preferred
Stock (filed as Exhibit A to the Registrant's
Registration Statement on Form 8-A12B on December 7, 1999,
File No. 778438-99-000016)
3.4* Registrant's First Amendment to Restated Bylaws dated
August 31, 1999 (filed as Exhibit 3.4 to the Registrant's
Annual Report on Form 10-K for the year ended
December 31, 1999, File No.1-9735)
4.1* Rights Agreement between Registrant and ChaseMellon
Shareholder Services, L.L.C. dated as of December 8,
1999 (filed by the Registrant on Form 8-A12B
on December 7, 1999, File No. 778438-99-000016)
10.1* Description of Cash Bonus Plan of Berry Petroleum
Company (filed as Exhibit 10.1 to the Registrant's
Annual Report on Form 10-K for the year ended
December 31, 1997, File No. 1-9735)
10.2* Salary Continuation Agreement dated as of December 5,
1997, by and between Registrant and Jerry V. Hoffman
(filed as Exhibit 10.2 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1997,
File No.1-9735)
10.3* Form of Salary Continuation Agreement dated as of
December 5, 1997, by and between Registrant and
Ralph J. Goehring and Michael R. Starzer (filed as
Exhibit 10.3 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1997,
File No. 1-9735)
10.4* Form of Salary Continuation Agreements dated as of
March 20, 1987, as amended August 28, 1987, by and
between Registrant and selected employees of the
Company (filed as Exhibit 10.12 to the Registration
Statement on Form S-1 filed on June 7, 1989,
File No. 33-29165)
10.5* Instrument for Settlement of Claims and Mutual Release
by and among Registrant, Victory Oil Company, the
Crail Fund and Victory Holding Company effective
October 31, 1986 (filed as Exhibit 10.13 to Amendment
No. 1 to the Registrant's Registration Statement on
Form S-4 filed on May 22, 1987, File No. 33-13240)
10.6* Warrant Certificate dated November 14, 1996, by and
between Registrant and Tannehill Oil Company (filed
as Exhibit 10.16 in Registrant's Form 10-K
filed on March 21, 1997, File No. 1-9735)
10.7* Amended and Restated Credit Agreement, dated as of
July 22, 1999, by and between the Registrant and
Bank of America, N.A., the First National Bank
of Chicago and other financial institutions (filed
as Exhibit 10.7 to the Registrant's Annual Report
on Form 10-K for the year ended December 31, 1999,
File No. 1-9735)
41
Exhibits (cont'd)
Exhibit No. Description of Exhibit Page
10.8* Standard Offer #2 Power Purchase Agreement dated
May 1984 by and between Registrant's predecessor and
Pacific Gas and Electric Company (filed as Exhibit
10.14 in Registrant's Form 10-K filed on March 21, 1997,
File No. 1-9735)
10.9* Standard Offer #1 Power Purchase Agreement dated
January 16, 1997, by and between Registrant and
Pacific Gas and Electric Company (filed as
Exhibit 10.15 in Registrant's Form 10-K filed on
March 21, 1997, File No. 1-9735)
10.10* Purchase and Sale Agreement, dated as of January 26,
1999, by and between the Registrant and Aera Energy LLC
(filed as Exhibit 10.1 to the Registrant's Form 8-K
filed on February 26, 1999, File No. 1-9735)
10.11* Standard Offer #2 Power Purchase Agreement (Newhall
Phase I), as amended, dated December 1985, between
Tenneco Oil Company and Southern California Edison
(filed as Exhibit 10.2 to the Registrant's Form 8-K
filed on February 26, 1999, File No. 1-9735)
10.12* Standard Offer #2 Power Purchase Agreement (Newhall
Phase II), as amended, dated December 1985, between
Tenneco Oil Company and Southern California Edison
(filed as Exhibit 10.3 to the Registrant's Form 8-K
filed on February 26, 1999, File No. 1-9735)
10.13* Amended and Restated 1994 Stock Option Plan (filed
as Exhibit 10.13 in Registrant's Form 10-K filed on
March 16, 1999, File No. 1-9735)
23.1 Consent of PricewaterhouseCoopers LLP 44
23.2 Consent of DeGolyer and MacNaughton 45
27** Financial Data Schedule
99.1 Undertaking for Form S-8 Registration Statements 47
99.2* Form of Indemnity Agreement of Registrant (filed as
Exhibit 28.2 in Registrant's Registration Statement
on Form S-4 filed on April 7, 1987, File No. 33-13240)
99.3* Form of "B" Group Trust (filed as Exhibit 28.3 to
Amendment No. 1 to Registrant's Registration Statement
on Form S-4 filed on May 22, 1987, File No. 33-13240)
* Incorporated by reference
** Included in the Company's electronic filing on EDGAR
42
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereto duly authorized on March 16, 2001.
BERRY PETROLEUM COMPANY
/s/ JERRY V. HOFFMAN /s/ RALPH J. GOEHRING /s/ DONALD A. DALE
JERRY V. HOFFMAN RALPH J. GOEHRING DONALD A. DALE
Chairman of the Board, Senior Vice President and Controller
Director, President and Chief Financial Officer (Principal
Chief Executive Officer (Principal Financial Officer) Accounting
Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities on the dates so indicated.
Name Office Date
/s/ Jerry V. Hoffman Chairman of the Board, Director, March 16, 2001
Jerry V. Hoffman President & Chief Executive Officer
/s/ William F. Berry Director March 16, 2001
William F. Berry
/s/ Ralph B. Busch, III Director March 16, 2001
Ralph B. Busch, III
/s/ William E. Bush, Jr. Director March 16, 2001
William E. Bush, Jr.
/s/ J. Herbert Gaul, Jr. Director March 16, 2001
J. Herbert Gaul, Jr.
/s/ John A. Hagg Director March 16, 2001
John A. Hagg
/s/ Thomas J. Jamieson Director March 16, 2001
Thomas J. Jamieson
/s/ Roger G. Martin Director March 16, 2001
Roger G. Martin
/s/ Martin H. Young, Jr. Director March 16, 2001
Martin H. Young, Jr.
43