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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, 2001
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)
5201 Truxtun Avenue, Suite 300
Bakersfield, California 93309
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (661) 616-
3900
(Former name, former address and former fiscal year, if changed
since last report)
28700 Hovey Hills Road, P.O. Box 925, Taft, California 93268
(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 15, 2002, the registrant had 20,832,996
shares of Class A Common Stock outstanding and the aggregate
market value of the voting stock held by nonaffiliates was
approximately $219,816,000. This calculation is based on the
closing price of the shares on the New York Stock Exchange on
February 15, 2002 of $14.17. The registrant also had 898,892
shares of Class B Stock outstanding on February 15, 2002, 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 7
Electricity Generation 7
Impact of Enron Bankruptcy 8
Environmental and Other Regulations 8
Competition 9
Employees 9
Oil and Gas Properties 9
Development 9
Exploration 11
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 7A. Quantitative and Qualitative Disclosures
About Market Risk 21
Item 8. Financial Statements and Supplementary Data 22
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 42
PART III
Item 10. Directors and Executive Officers of the Registrant 42
Item 11. Executive Compensation 42
Item 12. Security Ownership of Certain Beneficial
Owners and Management 42
Item 13. Certain Relationships and Related Transactions 42
PART IV
Item 14. Exhibits, Financial Statement Schedules
and Reports on Form 8-K 42
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, 2001. In March 2002, primarily in an effort to
improve its competitive position in attracting and retaining
talented personnel, the Company relocated its corporate
headquarters to Bakersfield, California from its properties in
the South Midway-Sunset field near Taft. Management believes
that these new facilities are adequate for its current operations
and anticipated growth.
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 be 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, its strong financial
position and its experienced management team. While the Company
continues to seek investment opportunities in California, the
Company intends to pursue opportunities in 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 over $100
million of 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, 2001, the Company's estimated proved
reserves were 103 million barrels of oil equivalent, (BOE), of
which 99% 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, 2001 were located in California,
with 74%, 20% and 4% 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 2001 was 5 million BOE, down 9% from 2000
production of 5.5 million BOE. For the five years 1997 through
2001, the Company's average annual reserve replacement rate was
102% and the finding and development cost was $3.69 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 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
3
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.
Revenues
The percentage of revenues by source for the prior three
years is as follows:
2001 2000 1999
Sales of oil and gas 72% 69% 66%
Sales of electricity 26% 31% 33%
Other 2% - 1%
Oil Marketing
The global and California crude oil markets have remained
very volatile due to the impacts of the September 11, 2001 (9/11)
terrorist attacks on the U.S. and as OPEC attempts to manage
crude oil prices in the midst of fluctuating inventory levels and
petroleum product demand weakness due to worldwide economic
slowdowns. Oil prices remained strong in 2001 until the economic
impacts of 9/11 caused the price to decline by $9/Bbl before
rebounding a few dollars. The price for West Texas Intermediate
(WTI), the U.S. benchmark crude oil, averaged $25.88 for 2001
compared to $30.26 in 2000 and $19.30 in 1999.
While the crude oil price differentials between WTI and
California's heavy crude has widened slightly over the last two
years, the Company believes that the differential will be near
its historical norms over the next several years. The crude
price differential between WTI and California's heavy crude oil
can be volatile and has averaged $7.25, $6.36 and $5.97 for 2001,
2000 and 1999, 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 sales agreement,
beginning in April 2000, with a major California refiner whereby
the Company sells in excess of 80% 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 also enters 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. In May of 2001, the
Company entered into a one-year zero cost bracketed collar on
3,000 barrels/day (BPD) of its crude oil. The maximum the
Company was obligated to pay under the hedge was $3.62/Bbl and
the maximum the Company could receive under the hedge was
$5.60/Bbl. The counterparty to this hedge, Enron, filed for
bankruptcy on December 2, 2001. As a result, the Company
terminated this contract on December 10, 2001. 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 BPD. Of this 6,500
BPD, Berry participated on 5,000 BPD above $15.50 per barrel and
on 1,500 BPD above $17.50 per barrel. These price triggers were
based on California heavy oil postings and both contracts expired
at December 31, 2000.
All of these price protection activities resulted in a net
(benefit) or cost/Bbl to the Company of ($.16) in 2001, $1.31 in
2000 and $.51 in 1999. Berry's 2001 average heavy crude oil
sales price was $19.70/Bbl, down $2.00, or 9% from $21.70 in
2000, and $13.08 in 1999.
4
The Company had no crude oil hedges in place at December 31,
2001. However, the Company has entered into oil price protection
hedges in 2002 for a one-year period beginning April 1, 2002 on a
total of 5,000 BPD. Based on WTI pricing, the hedges have a floor
of approximately $20.00/Bbl and a ceiling of approximately
$24.00/Bbl. In addition, 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 $14.30 (for 2002),
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.
Steaming Operations
At December 31, 2001, approximately 94% of the Company's
proved reserves, or 97 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, which is highly dependent on low-cost steam for
economic production. This purchase also included a 42 Mw
cogeneration facility consisting of two 21 Mw turbines. 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 may become advantageous to add
additional productive steam capacity for its requirements at
South Midway-Sunset and Placerita to allow for full development
of its properties. While the Company vigorously pursued the
possibility of constructing additional cogeneration facilities at
various locations on its properties in 2001, the regulation of
the electrical market in California is controlled by a very
politically-oriented state government. The Company has been
unsuccessful in obtaining an economic power sales agreement to
date and has reduced its efforts regarding such contracts until
the electrical marketplace in California becomes either less
controlled by the state government or until the marketplace
allows reasonable economics to prevail.
Midway-Sunset Field
For its South Midway-Sunset properties, the Company's steam
production for 2001 was generated by its 38 Mw and 18 Mw
cogeneration facilities (approximately 13,300 barrels of steam
per day (BSPD) including duct-fire, 21,000 BSPD in 2000) 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. 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. The Company
has the capability of generating approximately 17,000 BSPD from
conventional steam generators on its South Midway-Sunset
properties. On its North Midway-Sunset properties, the Company
relies solely on conventional steam generators, which have the
capability of generating approximately 3,400 BSPD, for its steam
requirements.
Placerita
On its Placerita properties, the Company generated
approximately 8,600 BSPD in 2001 (12,500 BSPD in 2000) from its
42 Mw cogeneration facility and has the capability of generating
another 7,600 BSPD from conventional steam generators.
5
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 2000,
versus an average of $2.74/Mmbtu in 1999. 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 2000 by
approximately $7.72/Mmbtu. This dramatic rise in natural gas
prices made conventional steaming operations uneconomic and,
thus, forced the Company to suspend most of its conventional
steaming operations. High natural gas prices in California
persisted into mid-2001. In August 2001, with SoCal prices at
approximately $4.00/Mmbtu, the Company began generating steam
from its conventional sources. For 2001, the cost of natural gas
purchased averaged $5.76/Mmbtu versus $4.95/Mmbtu in 2000. On
March 1, 2002, SoCal gas prices were approximately $2.40/Mmbtu.
Cogeneration Steam Generation
Going into 2001, the Company had four Standard Offer (SO)
electricity sales contracts related to its three cogeneration
plants. These contracts were based primarily on natural gas
costs, thus, as fuel costs rose so did the electrical revenues.
The actions that California's two largest utilities (Pacific
Gas and Electric Company (PG&E) and Southern California Edison
Company (Edison)) took in 2001 negatively impacted Berry and its
operations. Edison failed to pay Berry for November 2000 through
March 2001 power deliveries. PG&E made full payment for November
2000 and only partial payments, of approximately 15%, for
December 2000 and January 2001 deliveries before filing for
bankruptcy on April 6, 2001.
As a result of non-payment, the Company was forced to
suspend 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 and on Placerita Unit I (21 Mw) cogeneration
facility on April 6, 2001. The PG&E bankruptcy judge approved
Berry's contract terminations with PG&E in May of 2001 and on
June 14, 2001, the Company was able to restart its 38 Mw and 18
Mw cogeneration facilities by selling its electricity to a
creditworthy third party and began once again injecting steam
into its heavy oil reservoir at its South Midway-Sunset field.
6
Although Berry terminated its two contracts with Edison in
early 2001, Berry and Edison agreed to reinstate the contracts
under a revised pricing structure whereby Edison agreed to prepay
Berry for power deliveries. One contract continued to be based
on the cost of natural gas plus capacity payment while the second
contract has a fixed electricity sales price of 5.37 cents/kwh
plus capacity payment. Accordingly, the Company refired both
21Mw cogeneration facilities on June 27, 2001, thereby again
injecting steam into its heavy oil reservoir at its Placerita
field.
The Company believes that it will be able to deliver its
power generation in 2002 to paying customers and anticipates
steam generation volumes from its cogeneration facilities will be
similar to its pre-2001 historical levels. Until the Company can
re-establish economic long-term electricity sales contracts, the
cost of the Company's steam may be volatile from quarter to
quarter and year to year.
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 was constrained in
late 2000 and into 2001 and was at least partially responsible
for higher natural gas prices in California. In early 2001, the
Company subscribed to 12,000 Mmbtu/day of firm transportation for
a ten-year term on the expansion project on the Kern River
Pipeline. This project is expected to begin delivering gas in
mid-2003, although the project is awaiting FERC approval. The
Company has no assurance that it can procure its future natural
gas requirements at reasonable prices, however, the natural gas
constraint that occurred in late 2000 and early 2001 seems to
have abated and recent SoCal gas prices are similar to Henry Hub
prices.
6
Electricity Contracts
The following is a summary of the Company's cogeneration
electrical contracts and various operational data:
Average Average
megawatts barrels of
Type delivered steam
of Contract for sale delivered
Location Contract(1) Expira- per hour(2) per day (2)
tion
Purchaser
2001 2000 2001 2000
Placerita
Placerita I SO2 Edison 3-2009 13.4 16.7 5,075 6,112
Placerita II SO2 Edison 5-2002 10.1 16.4 3,707 6,404
South Midway-
Sunset
Cogen 18 Open Various 6-2002 7.9 14.3 3,570 6,350
Market
Cogen 38 Open Various 6-2002 20.6 34.5 9,723 15,115
Market
(1) SO is for "Standard Offer."
(2) Approximate average for 2001 based on 365 day year and 2000
based on 366 day year.
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. Expenses of operating the
cogeneration plants are analyzed monthly on a companywide basis.
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
a fuel for its cogeneration plants and steam generators. To
protect itself from a pending proposed decision by the California
Public Utilities Commission which would de-link 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 and $.4
million (net of tax effects) in other comprehensive income
related to unrecognized gains from these derivative instruments.
In 2001, the Company earned $1.4 million pre-tax from these
hedges which was recorded as a reduction to "Operating cost -
electricity generation". See Notes 2 and 3 of Notes to the
Financial Statements.
One of the Company's major challenges in 2001 was to obtain
the necessary approvals to sell the Company's electricity into
the marketplace and enter into a contract to sell power to a
creditworthy buyer. The Company terminated its two contracts
with PG&E on April 2, 2001, just four days before PG&E filed for
bankruptcy. On May 16, 2001, the PG&E bankruptcy judge approved
a settlement that the Company had reached with PG&E whereby the
utility would allow the Company to sell its power into the grid.
The Company immediately entered into a sales agreement with a
creditworthy third party and is delivering electricity into the
grid primarily via spot sales. The Company also pursues monthly
or longer-term sales arrangements. In September 2001, the
Company assigned its PG&E past-due receivables to a third party
for cash in the amount of $9.3 million.
7
Berry also terminated its two contracts with Edison, and
when Edison refused to acknowledge such terminations, Berry filed
the necessary lawsuits. In June 2001, Berry and Edison reached a
settlement whereby Edison would prepay Berry for power deliveries
and whereby Berry agreed to "standstill" on litigation matters
until December 31, 2001. Berry's Placerita II contract, which
expires in May 2002, stayed on a short-run avoided cost (SRAC)
pricing mechanism. Berry chose to elect the five-year fixed
price of 5.37 cents per kilowatt hour pricing mechanism on its
Placerita I contract, which expires in March 2009. These
contract amendments were approved by the CPUC in July 2001. The
Company entered into two additional contract amendments with
Edison whereby 1) the Company received 10% of the past-due amount
and 7% accrued interest on the past-due amount, and 2) the
Company extended its litigation standstill to allow Edison to
become creditworthy and Edison devised a formula payment,
although no specific date for payment was established. The
Company received interest monthly on the past due amount. At
December 31, 2001, Edison owed the Company $13.5 million and
Berry had $9.3 million recorded as collectible receivables; the
difference was written-off in early 2001. On March 1, 2002,
Edison paid the Company $13.5 million, representing the total
past due amount plus interest. The Company will record pre-tax
income of $4.2 million in the first quarter of 2002 related to
this cash receipt.
In late July 2001, Berry entered into a three-year SoCal gas
swap with Enron for a price of $4.20/Mmbtu on 5,000 Mmbtu/day.
The Company terminated this hedge contract with Enron on December
10, 2001, shortly after Enron declared bankruptcy and at the same
time, the Company terminated its crude oil price hedge with
Enron. The Company anticipates that it will enter into a similar
gas purchasing hedge in the near future to protect its favorable
spark spread related to Edison's fixed price contract.
Impact of Enron Bankruptcy
As previously described in "Oil Marketing" and "Electricity
Generation" the Company had commodity derivative contracts, both
oil and natural gas, in place when Enron declared bankruptcy on
December 2, 2001. On December 10, 2001, the Company elected to
terminate all contracts with Enron and agreed with Enron as to
the value of the contracts as of termination. Based on this
agreed value, the Company recorded a pre-tax charge of $1.5
million in the fourth quarter of 2001 and recorded a liability of
$1.3 million which is anticipated to be remitted upon the
approval of the termination agreement by the Enron bankruptcy
judge. The Company had a signed International Swap Dealer's
Association (ISDA) master agreement with Enron which allowed for
the netting of any receivables and liabilities arising
thereunder.
Environmental and Other Regulations
Berry Petroleum Company is committed to responsible
management of the environment, health and safety, as the
environment as the Company strives to achieve the long-term goal
of sustainable development. Berry 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. With safety protection one of the key focuses, the
Company has gone almost three years without a lost-time accident
by any of its employees.
The oil and gas production business in which Berry
participates is complex. All facets of the Company's operations
are affected by a myriad of federal, state, regional and local
laws, rules and regulations. Berry is further affected by
changes in such laws and by constantly changing administrative
regulations. Furthermore, government agencies may impose
substantial liabilities if the Company fails to comply with such
regulations or for any contamination resulting from the Company's
operations.
Therefore, Berry has programs in place to address risks, to
train employees in the proper performance of their duties and to
incorporate viable new technologies. 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.
Currently, California environmental laws and regulations are
being revised to provide for additional emission reductions.
Although these 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
8
in California. Berry believes that compliance with environmental
laws and regulations will not have a material adverse effect on
the Company's operations or financial condition. There can be no
assurances, however, that changes in, or additions to, laws and
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,
2001 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, 2001, the Company had 110 full-time
employees, down from 115 employees at year-end 2000.
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 2001, like 2000, the primary focus at Midway-Sunset
was continued development of the Formax properties acquired in
1996 and the continued application of horizontal well technology
in the Monarch sands. Of the 34 wells drilled in this field in
2001, 17 were drilled on the Formax properties, and 13 were
horizontal wells. The Company's objectives using this innovative
technology are to improve ultimate recovery of original oil-in-
place, reduce the development and operating costs of the
properties and accelerate production. In 2002, the Company plans
to drill an additional 39 wells in this field, including 13 on
the Formax properties, 11 of which will be horizontal.
Included in the Company's 2002 development plans for Midway-
Sunset are seven exploitation wells, in both the North and South
Midway-Sunset areas. In the North Midway-Sunset area, a corehole
will be drilled to evaluate the extent of the diatomite
accumulation in addition to four delineation wells to evaluate
the extent of our 2001 step-out discovery in the Upper Tulare
Zone.
Placerita - The Placerita property consists of six leases
(three federal) and three fee properties totaling approximately
750 acres. The Company estimates current reserves from Placerita
account for approximately 20% of Berry's proved oil and gas
reserves and approximately 19% of Berry's daily production. The
average depth of these wells is 1,800 feet and the properties
rely extensively on thermal methods, primarily steam flooding.
During 2001, the Company drilled three wells at Placerita,
one of which was a water disposal service well. The other two
wells were the first wells drilled as Phase One of a major
development campaign at the north end of the field. Included in
the Company's 2002 development plans for Placerita is the
continuation of the north end development with four steamflood
injection wells, three steamflood producers, and a step-out
evaluation well.
9
Montalvo - Berry owns a 100% working interest in six leases,
totaling 8,563 acres, in Ventura County, California comprising
the entire 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 7% of Berry's daily
production. The wells produce from an average depth of
approximately 11,500 feet. No new wells were drilled in 2001.
There are no plans at this time to drill any new wells in 2002,
however one remedial is planned. We are also pursuing the
possibility of running a seismic program over selected portions
of the developed area of the field in 2002 to confirm suspected
bypassed oil and gas accumulations in this highly faulted,
geologically complex field.
South Joe Creek - In April 2001, Berry purchased a 15.83%
non-operated working interest in the South Joe Creek coalbed
methane field. The Company purchased interests in federal, state
and local leases totaling approximately 5,800 acres in the
Campbell County portion of the Powder River Basin in Wyoming.
There were 18 wells (3 net) in existence at the time of the
purchase and 67 additional wells (11 net) were drilled in 2001.
Another 19 wells (3 net) are planned for drilling and completion
in 2002. On February 10, 2002, the production rate was 6.62
million cubic feet of gas (1.05 net) per day.
The following is a summary of the Company's capital
expenditures incurred during 2001 and 2000 and projected capital
expenditures for 2002.
CAPITAL EXPENDITURES SUMMARY
(in thousands)
2002(1) 2001 2000
(Projected)
South Midway-Sunset Field
New wells $6,550 $ 4,725 $ 10,128
Remedials/workovers 900 1,119 1,373
Facilities 1,380 3,785 1,333
------ ------ ------
8,830 9,629 12,834
------ ------ ------
Placerita
New wells 4,050 782 2,669
Remedials/workovers - 465 1,001
Facilities 4,495 1,660 4,543
------ ------ ------
8,545 2,907 8,213
------ ------ ------
North Midway-Sunset Field
New wells 840 74 1,257
Remedials/workovers - 248 212
Facilities - 284 76
------ ------ ------
840 606 1,545
------ ------ ------
Montalvo
Remedials/workovers 100 674 420
Facilities 265 331 1,295
------ ------ ------
365 1,005 1,715
------ ------ ------
South Joe Creek (2)
New wells 297 593 -
Facilities 248 79 -
------ ------ ------
545 672 -
------ ------ ------
Other 446 76 946
------ ------ ------
Totals $19,571 $14,895 $25,253
====== ====== ======
(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.
(2) Represents Berry's net share, or 15.83%, of the
total expenditures.
10
Exploration
The Company did not participate in the drilling of any
exploratory wells in 2001 or 2000 and has none budgeted for 2002.
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.
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, 2001. 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, 2001. 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:
2001 2000 1999
Net annual production:(1)
Oil (Mbbls) 4,996 5,434 5,060
Gas (Mmcf) 288 199 180
Total equivalent barrels(2) 5,044 5,467 5,090
Average sales price:
Oil (per Bbl) $19.70 $21.70 $13.08
Gas (per mcf) 5.09 4.34 1.90
Per BOE 19.79 21.72 13.07
Average operating cost - oil and gas 7.99 8.20 5.47
production (per BOE)(3)
(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 $1.31, $0.53 and $0 for
2001, 2000 and 1999, respectively. See Note 2 to the financial
statements.
11
Acreage and Wells
At December 31, 2001, the Company's properties accounted for
the following developed and undeveloped acres:
Developed Acres Undeveloped Acres
Gross Net Gross Net
California 7,226 7,226 7,244 7,244
Other 3,720 573 1,746 277
------ ------ ------ ------
10,946 7,799 8,990 7,521
====== ====== ====== ======
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 2,466 gross oil wells (2,461 net) and 88
gross gas wells (17 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:
2001 2000 1999
Gross Net Gross Net Gross Net
Exploratory
wells drilled:
Productive - - - - - -
Dry(1) - - - - - -
Development
wells drilled:(2)
Productive 103 47 81 81 21 21
Dry(1) 1 - - - - -
Total wells drilled:
Productive 103 47 81 81 21 21
Dry(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.
(2) Wells drilled for 2001 include 67 wells gross, 11 wells
net that were drilled at South Joe Creek which the Company
acquired in 2001 and holds a 15.83% working interest.
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, 2001)
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, 52, 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, 45, 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.
GEORGE T. CRAWFORD, 41, 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.
MICHAEL DUGINSKI, 35, is the Vice President of Corporate
Development. Mr. Duginski, a mechanical engineer, has a Masters
in Business Administration and was previously with Texaco, Inc.
where he was responsible for new business development and gas and
power operations. Mr. Duginski was hired by the Company
effective February 1, 2002.
BRIAN L. REHKOPF, 54, 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.
DONALD A. DALE, 55, has been Controller since December 1985.
KENNETH A. OLSON, 46, 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 2001 and 2000
are shown below:
2001 2000
Price Range Dividends Price Range Dividends
High Low per Share High Low Per Share
First $14.75 $12.05 $.10 $17.875 $14.063 $.10
Quarter
Second 15.05 11.00 .10 17.313 14.625 .10
Quarter
Third 16.99 13.65 .10 19.875 16.500 .10
Quarter
Fourth 17.75 14.26 .10 18.188 11.625 .10
Quarter
The closing price per share of Berry's Common Stock, as
reported on the New York Stock Exchange Composite Transaction
Reporting System for February 15, 2002, December 31, 2001 and
December 31, 2000 was $14.17, $15.70 and $13.375, respectively.
The number of holders of record of the Company's Common
Stock was 744 (and approximately 3,600 street name shareholders)
as of February 15, 2002. There was one Class B Stockholder of
record as of February 15, 2002.
In August 2001, the Board of Directors authorized the
Company to repurchase $20 million of Common Stock in the open
market. As of December 31, 2001, the Company had repurchased
308,075 shares for approximately $5.1 million. All shares
repurchased were retired.
Since Berry Petroleum Company's formation in 1985, the
Company has paid dividends on its Common Stock for eight
consecutive semi-annual periods through September 1989 and for 49
consecutive quarters through December 31, 2001. 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, 2001, 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, 2001 were derived from the audited
financial statements and the accompanying notes to those
financial statements (in thousands, except per share, per BOE and
% data):
2001 2000 1999 1998 1997
Statement of Operations Data:
Sales of oil and gas $100,146 $118,801 $ 66,615 $ 39,858 $ 67,172
Sales of electricity 35,917 52,765 33,731 15,680 17,190
Operating costs - oil and
gas production 40,281 44,837 27,829 18,272 22,589
Operating costs -
electricity generation 35,506 50,566 27,930 15,236 17,008
General and administrative
expenses (G&A) 7,174 7,754 6,269 3,975 5,907
Depreciation, depletion &
amortization (DD&A) 16,520 14,030 12,294 10,080 10,138
Net income 21,938 37,183 18,006 3,879 19,260
Basic net income per
share 1.00 1.69 .82 .18 .88
Weighted average number
of shares outstanding 21,973 22,029 22,010 22,007 21,976
Balance Sheet Data:
Working capital $ 5,837 $ (1,154)$ 8,435 $ 9,081 $ 11,499
Total assets 232,526 238,359 207,649 173,804 177,724
Long-term debt 25,000 25,000 52,000 30,000 32,000
Shareholders' equity 153,153 145,224 116,213 106,924 111,871
Cash dividends per share .40 .40 .40 .40 .40
Operating Data:
Cash flow from operations 35,433 65,934 24,809 19,924 31,401
Capital expenditures
(excluding acquisitions) 14,895 25,253 9,122 6,981 18,597
Property/facility -
acquisitions 2,273 3,182 33,605 2,991 -
Oil and gas producing
operations (per BOE):
Average sales price $ 19.79 $ 21.72 $ 13.07 $ 9.05 $ 14.71
Average operating cost(1) 7.99 8.20 5.47 4.15 4.96
G&A 1.42 1.42 1.23 .90 1.30
------ ------ ------ ------ ------
Cash flow 10.38 12.10 6.37 4.00 8.45
DD&A 3.28 2.57 2.42 2.29 2.23
------ ------ ------ ------ ------
Operating income $ 7.10 $ 9.53 $ 3.95 $ 1.71 $ 6.22
====== ====== ====== ====== ======
Production (BOE) 5,044 5,467 5,090 4,399 4,550
Production (Mwh) 456 764 728 448 446
Proved Reserves Information:
Total BOE 102,855 107,361 112,541 92,609 101,043
Present value (PV10) of
estimated future cash
flow before income taxes $356,556 $721,770 $714,555 $113,811 $376,459
Year-end average BOE
price for PV10 purposes 14.18 20.63 19.41 7.05 12.19
Other:
Return on average
shareholders' equity 14.7% 28.5% 16.5% 3.5% 18.1%
Return on average total
assets 8.7% 16.8% 9.0% 2.2% 10.9%
Total debt/total debt
plus equity 14.0% 14.7% 30.9% 21.9% 22.2%
Year-end stock price $ 15.70 $ 13.375 $ 15.125 $ 14.188 $ 17.438
Year-end market
capitalization $341,192 $294,699 $332,920 $312,247 $383,510
(1) Including monthly
expenses in excess of
monthly revenues from
cogeneration operations $ 1.31 $ 0.53 $ - $ 0.14 $ 0.48
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,
2001, 2000 and 1999 and the financial condition, liquidity and
capital resources as of December 31, 2001 and 2000. 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 natural
gas and electricity will fluctuate from one period to another due
to regional market conditions and other factors, while oil prices
will be predominantly 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
The Company earned $21.9 million, or $1.00 per share, in
2001, down 41% from $37.2 million, or $1.69 per share, in 2000,
but up 22% from $18 million, or $.82 per share in 1999. Income
earned in 2001 represents the second highest income ever achieved
by the Company, exceeded only by the $37.2 million earned in
2000. The decrease in income from 2000 was primarily related to
lower crude oil prices and lower production which was a direct
result of the suspension of steam operations in 2001 due to the
California energy crisis and the writedown of electricity
receivables from two of California's insolvent public utilities.
The following table presents certain operating data for the
years ended December 31, 2001, 2000 and 1999:
2001 2000 1999
Oil and Gas
Net production - BOE/D 13,820 14,937 13,946
Per BOE:
Average sales price $19.79 $21.72 $13.07
Operating costs(1) 7.50 7.77 4.95
Production taxes .49 .43 .52
Total operating costs 7.99 8.20 5.47
DD&A 3.28 2.57 2.42
G&A 1.42 1.42 1.23
Interest expense .74 .58 .78
Electricity
Electric power produced -
megawatt (Mw) hrs/day 1,251 1,979 1,957
Average sales price/Mw $78.68 $72.85 $47.22
Fuel gas cost/Mmbtu 5.76 4.95 2.74
(1) Including monthly expenses in excess
of monthly revenues from cogeneration
operations of $1.31, $0.53 and $0 in
2001, 2000 and 1999, respectively.
BOE/D - Barrels of oil equivalent per day
16
Operating income from oil and gas producing operations was
$42.2 million in 2001, down from $60.3 million in 2000, but up
from $26.8 million in 1999. The decrease from 2000 was primarily
due to lower sales of oil and gas and higher DD&A, partially
offset by lower operating costs. Sales of oil and gas were
$100.1 million in 2001, down from $118.8 million in 2000, but
higher than $66.6 million in 1999. The decrease from 2000 was
related to both lower production and sales prices and the
increase from 1999 was due to higher oil prices partially offset
by slightly lower production. Production in 2001 at 13,820 BOE/D
was 7% and 1% lower than 14,937 in 2000 and 13,946 in 1999,
respectively. Production for 2001 peaked at approximately 16,000
BOE/D in the first quarter before the effects of the suspension
of steaming operations took effect. The extremely high natural
gas costs during the California energy crisis and the suspension
of utility payments for cogeneration power made steaming
uneconomic for several months in the first half of 2001. The
Company was forced to curtail conventional steaming operations in
late 2000 and suspend the majority of its cogeneration operations
in February 2001 with the remaining turbine shut-in in early
April. In June, the Company began increasing its steaming
activities, with normal injection levels re-established in
August. Due to the steam curtailment, crude oil production fell
to a low of approximately 12,800 BOE/D before recovering to a
level of approximately 14,000 BOE/D at year-end. The Company
expects 2002 crude oil production levels to average approximately
15,000 BOE/D.
Oil prices for 2001 were quite strong until the aftermath of
September 11 reduced worldwide demand for crude oil and refined
products. The average price received/BOE in 2001 of $19.79 was
only slightly lower than $21.72 in 2000 and was 51% higher than
$13.07 received in 1999. Post September 11, crude oil prices
fell $9/Bbl to a low of $11.00 for California heavy oil but
subsequently rebounded to $13.25/Bbl at year-end and to $15.25 as
of February 13, 2002.
Operating costs per barrel in 2001 were $7.99, down from
$8.20 in 2000, but higher than $5.47 in 1999. The most
significant factor in the reduction of operating costs from 2000
was the suspension of steaming operations. Not only was the cost
of gas dramatically reduced, but other factors in the Company's
cost structure, such as production rig cost, chemicals for water
treating and other areas were greatly diminished or eliminated
for the period in which steaming was suspended. Although the
suspension was a positive factor in lowering operating costs in
2001, it did, of course, come at the cost of declining production
levels. Other factors contributing to the decline in operating
costs were the 3D project performed on the Company's Midway-
Sunset properties in 2000, higher environmental remediation costs
in 2000 and savings from facility consolidation projects on
several of the Company's core properties in 2001. It should be
pointed out that in the period of suspended cogeneration
operations, it was necessary to purchase additional electricity
from two California utilities at very high per unit costs which
resulted in an increase in power costs of approximately $1.1
million over 2000 levels. The Company estimates that the
operating cost per barrel in 2002 will average $7.00 to $8.00
given the current development plan and operating environment.
The Company has seen a drastic decline in electricity prices
during 2001. Although the average price received for the
Company's power was comparable at $.078/Kwh for both 2000 and
2001, the trend in electricity pricing is toward much lower
prices which had a negative impact on the Company's steam costs
in the fourth quarter of 2001 and will also affect 2002 costs and
beyond. Although the Company has negotiated electricity sales
contracts on its two Placerita turbines at attractive prices, the
remaining electricity generated is sold on the open market which
currently has been priced at just $.025/Kwh.
As the Company entered 2001, the California energy crisis
was just unfolding. Two of the state's major utilities were
experiencing extreme cash flow problems related to their
inability to pass their cost to obtain electricity to retail and
industrial customers. Therefore, in the early portion of 2001,
these two utilities suspended payment for electric power produced
by the Company under longstanding Standard Offer contracts. The
Company was forced to take actions to protect the liquidity of
the Company. Prior to Pacific Gas and Electric Company's (PG&E)
bankruptcy, the Company terminated its power purchase contracts
with PG&E. The Bankruptcy Court confirmed these terminations and
Berry paid $.2 million pursuant to the settlement and stipulation
with PG&E. In June 2001, the Company entered into a contract
with a creditworthy power marketer and re-established power
production from its homebase cogeneration capacity. In September
2001, the Company assigned its past-due receivables for
approximately 77% of the balance owed by PG&E which effectively
ended the Company's direct involvement with PG&E's default.
The Company filed litigation against Edison and the
California Independent System Operator (ISO) on May 2 and May 7,
2001 to recover non-payment for deliveries of electricity from
November 2000 through March 2001 and to resolve other contractual
matters. The lawsuits were ultimately coordinated with those of
other "qualified facilities" and, on June 27, 2001, the Company
and Edison entered into amendments with respect to its existing
Power Purchase Agreements which
17
became effective on July 18, 2001. The amendments provided for
a standstill of litigation and other matters. On August 27,
2001, the Company entered into Implementing Agreements concerning
these amendments requiring the suspension of legal proceedings
during the agreed to "Standstill Period". The above agreements
were approved by the Court on September 19, 2001. One of the two
agreements will expire under its own terms in May 2002, at which
time the Company will need to make other arrangements for the
sale of the corresponding electricity production. The Standstill
Period was extended by a further amendment on December 10, 2001
and a payment formula was established whereby Edison was to make
payments, although there was no date identified. Additionally,
Edison was required to make monthly payments in advance for power
to be delivered and to make interest payments on the outstanding
balance until the balance is paid or the amendments terminate.
On March 1, 2002, Edison paid the Company $13.5 million,
representing the total past-due amount plus interest. The
Company will record pre-tax income of $4.2 million in the first
quarter of 2002 related to this cash receipt.
At year-end the Company had no commodity hedges in place.
In December, the Company terminated its crude oil and natural gas
derivative contracts with Enron and recognized a net pre-tax loss
on termination of these contracts of $1.5 million. The Company
anticipates that it will enter into similar gas purchase hedges
in the near future in an effort to manage its "spark spread" (the
difference between the price received for the sale of electricity
and the cost of natural gas) and lower its operating costs.
DD&A on a per barrel basis increased to $3.28, up from $2.57
in 2000 and $2.42 in 1999. The increase from prior years was
primarily due to a higher depreciable basis resulting from the
2001 and 2000 development activity and facility improvements at
the Company's cogeneration facilities and the amortization of the
remaining capitalized costs related to the Standard Offer
electricity sales contracts which were terminated in 2001. The
Company expects DD&A to be slightly lower in 2002 compared to
2001.
General
G&A expenses in 2001 were $7.2 million, or $1.42 per BOE,
down 8% from $7.8 million in 2000, but up 14% from $6.3 million
in 1999. The decrease from 2000 was primarily the result of
lower personnel costs, legal expenses and consulting charges.
The Company expects similar G&A expenses in 2002 compared to
2001.
Interest expense increased in 2001 to $3.7 million from $3.2
million in 2000, but decreased from $4.0 million in 1999. To
ensure liquidity, the Company drew down $45 million from its
credit facility in early 2001 to compensate for the large unpaid
receivables from electricity sales in late 2000 and the early
months of 2001. The receivable for one of the two utilities was
sold in the third quarter eliminating approximately half of the
remaining receivable balance. These funds and internally
generated funds were sufficient to pay off the $45 million
drawdown by the end of the third quarter of 2001. The debt
repayment along with much lower interest rates has resulted in
lower interest costs incurred thus far in 2002 compared to the
average rate experienced in 2001.
The Company experienced an effective income tax rate of
19.5% in 2001, down from 28% and 21% in 2000 and 1999,
respectively. The lower effective tax rate is primarily a result
of significant enhanced oil recovery (EOR) tax credits earned by
the Company's continued investment in the development of its
thermal EOR projects, both through capital expenditures and
continued steam injection volumes. This is the fourth
consecutive year that the Company has achieved an effective tax
rate below 30%, versus the combined federal and state statutory
rate of 40%. The Company believes it will continue to earn
significant EOR tax credits and have an effective tax rate below
30% in 2002.
Financial Condition, Liquidity and Capital Resources
Working capital at December 31, 2001 was $5.8 million, up
from ($1.2) million at December 31, 2000, but down from $8.4
million in 1999. Net cash provided by operations was $35.4
million, down 46% from the all-time record of $65.9 million
achieved in 2000, but 43% higher than $24.8 million in 1999. The
Company used these funds to pay for capital expenditures of $14.9
million, pay dividends of $8.8 million, acquire an interest in
producing properties and drillable acreage of $2.3 million and
increase the company's cash balance by $4.5 million to a healthy
balance of $7.2 million at December 31, 2001. The Company's net
debt (i.e., its outstanding long-term debt of $25 million less
working capital) was $19.2 million.
18
The Company has a $150 million revolving bank facility with
a banking group. As of December 31, 2001, approximately $118
million is available under the agreement after deducting the $25
million long-term debt and $6.7 million in outstanding Letters of
Credit.
As of June 30, 2001, the Company was owed $15.0 million by
Edison for power produced between November 2000 and March 2001.
In the third quarter of 2001, $1.5 million of the total was
received, leaving a remaining balance of $13.5 million as of
December 31, 2001. Of this balance, $9.3 million was recorded as
collectible receivables at December 31, 2001. On March 1, 2002,
Edison paid the Company $13.5 million, representing the total
amount due plus interest. The Company presently intends to use
these funds to reduce its long-term debt of $25 million to
approximately $12 million.
In August 2001, the Board of Directors authorized the
Company to repurchase $20 million of Common Stock in the open
market. As of December 31, 2001, the Company had repurchased
308,075 shares for approximately $5.1 million. All shares
repurchased were retired.
The Company has budgeted $19.6 million in capital projects
in 2002 consisting of the drilling of 52 Company operated wells
on its core California properties, 11 of which will be
horizontal, and 33 non-operated (gross wells) in the South Joe
Creek field in Wyoming. The development program will also
include 31 remedial jobs and other facility improvements of $6.4
million all at the Company's core California properties.
At year-end, the Company had no subsidiaries, no special
purpose entities and no off-balance sheet debt. The Company did
not enter into any significant related party transactions in
2001.
Critical Accounting Policies
The preparation of financial statements in conformity with
generally accepted accounting principles requires Management to
make estimates and assumptions for the reporting period and as of
the financial statement date. These estimates and assumptions
affect the reported amounts of assets and liabilities, the
disclosure of contingent liabilities and the reported amounts of
revenues and expenses. Actual results could differ from those
amounts.
A critical accounting policy is one that is important to the
portrayal of the Company's financial condition and results, and
requires Management to make difficult subjective and/or complex
judgments. Critical accounting policies cover accounting matters
that are inherently uncertain because the future resolution of
such matters is unknown. The Company believes the following
accounting policies are critical policies; accounting for oil and
gas reserves, environmental liabilities, income taxes and asset
retirement obligations.
Oil and gas reserves include proved reserves that represent
estimated quantities of crude oil and natural gas in which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. The oil and
gas reserves are based on estimates prepared by independent
engineering consultants and are used to calculate DD&A and
determine if any potential impairment exists related to the
recorded value of the Company's oil and gas properties.
The Company reviews, on a quarterly basis, its estimates of
costs of compliance with environmental laws and the cleanup of
various sites, including sites in which governmental agencies
have designated the Company as a potentially responsible party.
When it is probable that obligations have been incurred and where
a minimum cost or a reasonable estimate of the cost of compliance
or remediation can be determined, the applicable amount is
accrued.
The Company makes certain estimates, which may include
various tax planning strategies, in determining taxable income,
the timing of deductions and the utilization of tax attributes.
Management is required to make judgments based on historical
experience and future expectations on the future abandonment
cost, net of salvage value, of its oil and gas properties and
equipment. The Company reviews its estimate of the future
obligation periodically and accrues the estimated obligation
monthly based on the units of production method.
19
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.
Recent Accounting Developments
In July 2001, the Financial Accounting Standards Boards
(FASB) issued SFAS No. 141, "Business Combinations," which
supersedes Accounting Principles Board Opinion (APB) No. 16,
"Business Combinations." This Statement requires that all
business combinations be accounted for by the purchase method,
establishes specific criteria for the recognition of intangible
assets separately from goodwill and requires unallocated negative
goodwill to be written off immediately as an extraordinary gain.
The provisions of the Statement apply to business combinations
initiated after June 30, 2001. For business combinations
accounted for using the purchase method before July 1, 2001, the
provisions of this Statement will be effective in the first
quarter of 2002. The Company anticipates that the impact of this
new standard will have an immaterial impact on the financial
statements taken as a whole.
In July 2001, the Financial Accounting Standard Board (FASB)
issued Statement of Financial Accounting Standards (SFAS) No.
142, "Goodwill and Other Intangible Assets," which supersedes the
Accounting Principles Board (APB) Opinion No. 17, "Intangible
Assets." This Statement addresses the accounting and reporting
of goodwill and other intangible assets subsequent to their
acquisition. The Statement also provides specific guidance on
testing goodwill and intangible assets for impairment. SFAS No.
142 provides that (i) goodwill and indefinite-lived intangible
assets will no longer be amortized, (ii) impairment will be
measured using various valuation techniques based on discounted
cash flows, (iii) goodwill will be tested for impairment at least
annually at the reporting unit level, (iv) intangible assets
deemed to have an indefinite life will be tested for impairment
at least annually and (v) intangible assets with finite lives
will be amortized over their useful lives. All provisions of
this Statement will be effective in the first quarter of 2002.
The Company anticipates that the impact of this new standard will
have an immaterial impact on the financial statements taken as a
whole.
In August 2001, the FASB issued SFAS No. 143, "Accounting
for Asset Retirement Obligations," which addresses financial
accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs. This Statement requires that the fair value of
a liability for an asset retirement obligation be recognized in
the period in which it is incurred if a reasonable estimate of
fair value can be made. The associated asset retirement costs
are capitalized as part of the carrying amount of the long-lived
asset. All provisions of this Statement will be effective at the
beginning of fiscal 2003. The Company is in the process of
determining the impact of this standard on the Company's
financial results when effective.
In October 2001, the FASB issued SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets." This
Statement supersedes SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
and amends APB No. 30, "Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions." This Statement
requires that long-lived assets that are to be disposed of by
sale be measured at the lower of book value or fair value less
costs to sell. SFAS No. 144 retains the fundamental provisions
of SFAS 121 for (a) recognition and measurement of the impairment
of long-lived assets to be held and used and (b) measurement of
long-lived assets to be disposed of by sale. This Statement also
retains APB No. 30's requirement that companies report
discontinued operations separately from continuing operations.
All provisions of this Statement will be effective in the first
quarter of 2002. The Company anticipates that the impact of this
new standard will have an immaterial impact on the financial
statements taken as a whole.
20
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk
The Company has significant market risk exposure related to
the prices received for the sale of its crude oil. A $1 change
in oil price will equate to an approximately $5.5 million change
in annual revenues. The Company periodically enters into hedge
contracts to manage the oil price risk. The Company had no crude
oil hedges in place at December 31, 2001. However, the Company
has entered into oil price protection hedges in 2002 for a one-
year period beginning April 1, 2002 on a total of 5,000 BPD.
Based on WTI pricing, the hedges have a floor of approximately
$20.00/Bbl and a ceiling of approximately $24.00/Bbl. The Company
is also at risk for a widening of the differential between the
WTI crude oil price and the posted price of the Company's heavy
crude oil. To minimize this risk, the Company has a sales
contract in place through March 31, 2003 for over 80% of its
crude oil production which is priced at the higher of (1) local
field posting plus a bonus, (2)WTI minus a fixed differential
or (3)a fixed percentage of WTI.
The Company also has market risk exposure related to the
price received for the sale of its electricity production and the
cost paid by the Company for the natural gas used in its
cogeneration operations. The Company's three cogeneration
facilities, when combined, have electricity production capacity
of 98 Mw of electricity/hour (Mwh). Of this total, the Company
sells approximately 92 Mwh and the remaining 6 Mwh is consumed in
the Company's operations. The Company's goal is to control its
"spark spread" (the difference between the sales price received
for its electricity and the cost to purchase natural gas used as
fuel in the cogeneration operations). This was an extremely
difficult goal to achieve during 2001 primarily due our early
electrical contract terminations arising out of the utility
purchasers' default and the volatility in the electrical market
and in natural gas prices. The Company consumes approximately
27,000 Mmbtu/day of natural gas as fuel in these facilities. A
change of $.10/Mmbtu in the cost of natural gas equates to
a change of approximately $1.0 million in operating costs.
The Company has a long-term electricity sales contract in
place at a fixed price of $53.70/Mwh plus capacity on
approximately 19 Mwh of electricity production with a major
utility. A change of $1/Mwh in the price received for
electricity on the remaining 73 Mwh equates to approximately $.6
million in annual revenues. The Company is a party to another
electricity sales contract for approximately 19 Mwh that is based
on a short-run avoided cost (SRAC) pricing mechanism. This
provides the Company an electricity price that is directly
related to the cost of natural gas. However, this contract
terminates in May 2002, whereupon this volume may be sold on the
open market. The remainder of the electricity is sold primarily
on the open market to a creditworthy customer. As the
electricity market stabilizes in California, the Company
anticipates entering into longer-term sales contracts for its
electricity. The Company was able to enter into a four-month
sales contract through June 30, 2002 under which the Company will
deliver 25 Mwh of electricity, plus a cash payment, in exchange
for a sufficient volume of natural gas needed to generate the 25
Mwh of electricity to fulfill the contract, thereby protecting
the spark spread on this volume. The Company is pursuing longer-
term arrangements on the sale of its electricity and may enter
into additional hedges on its natural gas purchases to seek to
improve the spark spread related to these non-utility volumes.
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, gas
transportation availability, 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.
21
Item 8. Financial Statements and Supplementary Data
BERRY PETROLEUM COMPANY
Index to Financial Statements and
Supplementary Data
Page
Report of PricewaterhouseCoopers LLP,
Independent Accountants 23
Balance Sheets at December 31, 2001 and 2000 24
Statements of Operations for the
Years Ended December 31, 2001, 2000 and 1999 25
Statements of Comprehensive Income for the
Years Ended December 31, 2001, 2000 and 1999 25
Statements of Shareholders' Equity for the
Years Ended December 31, 2001, 2000 and 1999 26
Statements of Cash Flows for the
Years Ended December 31, 2001, 2000 and 1999 27
Notes to the Financial Statements 28
Supplemental Information About Oil & Gas
Producing Activities 40
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.
22
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 comprehensive income, shareholders'
equity and cash flows present fairly, in all material respects,
the financial position of Berry Petroleum Company (the "Company")
at December 31, 2001 and 2000, and the results of its operations
and its cash flows for each of the three years in the period
ended December 31, 2001 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
February 11, 2002, except as to Note 14,
which is as of March 1, 2002
Los Angeles, California
23
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 2001 and 2000
(In Thousands, Except Share Information)
2001 2000
ASSETS
Current assets:
Cash and cash equivalents $ 7,238 $ 2,731
Short-term investments available for sale 594 582
Accounts receivable 17,577 26,420
Prepaid expenses and other 2,792 5,190
-------- --------
Total current assets 28,201 34,923
Oil and gas properties (successful efforts 203,413 201,643
basis), buildings and equipment, net
Other assets 912 1,793
-------- --------
$ 232,526 $ 238,359
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 11,197 $ 28,678
Accrued liabilities 7,089 2,288
Federal and state income taxes payable 4,078 5,110
-------- --------
Total current liabilities 22,364 36,076
Long-term debt 25,000 25,000
Deferred income taxes 32,009 32,059
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; 20,833,094 shares issued and
outstanding (21,134,667 in 2000) 208 211
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 48,905 53,686
Accumulated other comprehensive income - 441
Retained earnings 104,031 90,877
-------- --------
Total shareholders' equity 153,153 145,224
-------- --------
$ 232,526 $ 238,359
======== ========
The accompanying notes are an integral part of these financial
statements.
24
BERRY PETROLEUM COMPANY
Statements of Operations
Years ended December 31, 2001, 2000 and 1999
(In Thousands, Except Per Share Data)
2001 2000 1999
Revenues:
Sales of oil and gas $ 100,146 $ 118,801 $ 66,615
Sales of electricity 35,917 52,765 33,731
Interest and dividend income 2,150 447 674
Other income 328 36 186
-------- -------- --------
138,541 172,049 101,206
-------- -------- --------
Expenses:
Operating costs - oil and gas
production 40,281 44,837 27,829
Operating costs - electricity
generation 35,506 50,566 27,930
Depreciation, depletion &
amortization 16,520 14,030 12,294
General and administrative 7,174 7,754 6,269
Interest expense 3,719 3,186 3,973
Write-off of electricity receivables 6,645 - -
Termination of derivative contracts 1,458 - -
-------- -------- --------
111,303 120,373 78,295
-------- -------- --------
Income before income taxes 27,238 51,676 22,911
Provision for income taxes 5,300 14,493 4,905
-------- -------- --------
Net income $ 21,938 $ 37,183 $ 18,006
======== ======== ========
Basic net income per share $ 1.00 $ 1.69 $ .82
======== ======== ========
Diluted net income per share $ .99 $ 1.67 $ .82
======== ======== ========
Weighted average number of shares of
capital stock outstanding (used to
calculate basic net income per share) 21,973 22,029 22,010
Effect of dilutive securities:
Employee stock options 113 185 32
Other 24 26 7
-------- -------- --------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 22,110 22,240 22,049
======== ======== ========
Statements of Comprehensive Income
Years Ended December 31, 2001, 2000 and 1999
(In Thousands)
2001 2000 1999
Net income $ 21,938 $ 37,183 $ 18,006
(Realized) unrealized gains on
derivatives (441) 441 -
------- ------- -------
Comprehensive income $ 21,497 $ 37,624 $ 18,006
======= ======= =======
The accompanying notes are an integral part of these financial
statements.
25
BERRY PETROLEUM COMPANY
Statements of Shareholders' Equity
Years Ended December 31, 2001, 2000 and 1999
(In Thousands, Except Per Share Data)
Accumul
Capital ated
in Retained Other Shareholder's
Class A Class Excess of Earnings Compreh Equity
B Par Value ensive
Income
Balances at January $ 211 $ 9 $ 53,400 $ 53,304 $ - $ 106,924
1, 1999
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
Stock options
exercised - - 172 - - 172
Deferred director
fees - stock
compensation - - 156 - - 156
Common stock
repurchases (3) - (5,109) - - (5,112)
Cash dividends
declared -
$.40 per share - - - (8,784) - (8,784)
Realized gains on
derivatives - - - - (441) (441)
Net income - - - 21,938 - 21,938
----- ----- ------ ------- ----- -------
Balances at
December 31, 2001 $ 208 $ 9 $ 48,905 $104,031 $ - $ 153,153
===== ===== ====== ======= ===== =======
The accompanying notes are an integral part of these financial
statements.
26
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 2001, 2000 and 1999
(In Thousands)
2001 2000 1999
Cash flows from operating activities:
Net income $ 21,938 $ 37,183 $ 18,006
Depreciation, depletion and
amortization 16,520 14,030 12,294
(Decrease) increase in deferred income
tax liability (50) 3,147 263
Other, net (505) 249 (208)
------- ------- -------
Net working capital provided by
operating activities 37,903 54,609 30,355
Decrease (increase) in current assets
other than cash, cash equivalents
and short-term investments 11,241 (14,227) (7,839)
(Decrease) increase in current
liabilities other than notes payable (13,711) 25,552 2,293
------- ------- -------
Net cash provided by operating activities 35,433 65,934 24,809
------- ------- -------
Cash flows from investing activities:
Capital expenditures, excluding
property acquisitions (14,895) (25,253) (9,122)
Property/facility acquisitions (2,273) (3,182) (33,605)
Proceeds from sale of assets 151 49 21
Purchase of short-term investments (1,183) (584) (611)
Maturities of short-term investments 1,171 600 725
Contract purchases - - (1,028)
------- ------- -------
Net cash used in investing activities (17,029) (28,370) (43,620)
------- ------- -------
Cash flows from financing activities:
Proceeds from issuance of long-term debt 45,000 1,000 35,000
Payment of long-term debt (45,000) (28,000) (13,000)
Dividends paid (8,784) (8,812) (8,804)
Share repurchase program (5,112) - -
Other, net (1) (1) (463)
------- ------- -------
Net cash (used in) provided by financing
activities (13,897) (35,813) 12,733
------- ------- -------
Net increase (decrease) in cash and cash
equivalents 4,507 1,751 (6,078)
Cash and cash equivalents at beginning
of year 2,731 980 7,058
------- ------- -------
Cash and cash equivalents at end of year $ 7,238 $ 2,731 $ 980
======= ======= =======
Supplemental disclosures of cash flow
information:
Interest paid $ 3,532 $ 2,999 $ 4,546
======= ======= =======
Income taxes paid $ 5,635 $ 9,712 $ 4,079
======= ======= =======
The accompanying notes are an integral part of these financial
statements.
27
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, pipeline
companies or refiners. 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.
28
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (cont'd)
Environmental Expenditures
The Company reviews, on a quarterly basis, its estimates of
costs of compliance with environmental laws and the cleanup of
various sites, including sites in which governmental agencies
have designated the Company as a potentially responsible party.
When it is probable that obligations have been incurred and where
a minimum cost or a reasonable estimate of the cost of compliance
or remediation can be determined, the applicable amount is
accrued. For other potential liabilities, the timing of accruals
coincides with the related ongoing site assessments. Liabilities
are not discounted.
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 (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities", which established
new accounting and reporting requirements for derivative
instruments and hedging activities. SFAS No. 133, as amended by
SFAS No. 138, 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 is generally established at the inception of a
derivative. For derivatives designated as cash flow hedges and
meeting the effectiveness guidelines of SFAS No. 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. 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 each monthly accounting period, the cost
of operating the cogeneration facilities, 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).
Shipping and Handling Costs
Shipping and handling costs, which consist primarily of
natural gas transportation costs, are included in both "Operating
costs - oil and gas production" and "Operating costs -electricity
generation." Natural gas transportation costs categories were
$1.2 million, $1.6 million and $1.4 million for 2001, 2000 and
1999, respectively.
29
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (cont'd)
Stock-Based Compensation
As allowed in SFAS No. 123, "Accounting for Stock-Based
Compensation", the Company continues to apply Accounting
Principles Board Opinion (APB) No. 25, "Accounting for Stock
Issued to Employees", and related interpretations in recording
compensation related to its plans. The supplemental disclosure
requirements of SFAS No. 123 and further information related to
the Company's stock option plans are presented in Note 11 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 July 2001, the Financial Accounting Standards Boards
(FASB) issued SFAS No. 141, "Business Combinations," which
supersedes Accounting Principles Board Opinion (APB) No. 16,
"Business Combinations." This Statement requires that all
business combinations be accounted for by the purchase method,
establishes specific criteria for the recognition of intangible
assets separately from goodwill and requires unallocated negative
goodwill to be written off immediately as an extraordinary gain.
The provisions of the Statement apply to business combinations
initiated after June 30, 2001. For business combinations
accounted for using the purchase method before July 1, 2001, the
provisions of this Statement will be effective in the first
quarter of 2002. The Company anticipates that the impact of this
new standard will have an immaterial impact on the financial
statements taken as a whole.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and
Other Intangible Assets," which supersedes the APB Opinion No.
17, "Intangible Assets." This Statement addresses the accounting
and reporting of goodwill and other intangible assets subsequent
to their acquisition. The Statement also provides specific
guidance on testing goodwill and intangible assets for
impairment. SFAS No. 142 provides that (i) goodwill and
indefinite-lived intangible assets will no longer be amortized,
(ii) impairment will be measured using various valuation
techniques based on discounted cash flows, (iii) goodwill will be
tested for impairment at least annually at the reporting unit
level, (iv) intangible assets deemed to have an indefinite life
will be tested for impairment at least annually and (v)
intangible assets with finite lives will be amortized over their
useful lives. All provisions of this Statement will be effective
in the first quarter of 2002. The Company anticipates that the
impact of this new standard will have an immaterial impact on the
financial statements taken as a whole.
In August 2001, the FASB issued SFAS No. 143, "Accounting
for Asset Retirement Obligations," which addresses financial
accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs. This Statement requires that the fair value of
a liability for an asset retirement obligation be recognized in
the period in which it is incurred if a reasonable estimate of
fair value can be made. The associated asset
30
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (cont'd)
retirement costs are capitalized as part of the carrying amount
of the long-lived asset. All provisions of this Statement will
be effective at the beginning of fiscal 2003. The Company is in
the process of determining the impact of this standard on the
Company's financial results when effective.
In October 2001, the FASB issued SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets." This
Statement supersedes SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
and amends APB No. 30, "Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions." This Statement
requires that long-lived assets that are to be disposed of by
sale be measured at the lower of book value or fair value less
costs to sell. SFAS No. 144 retains the fundamental provisions
of SFAS 121 for (a) recognition and measurement of the impairment
of long-lived assets to be held and used and (b) measurement of
long-lived assets to be disposed of by sale. This Statement also
retains APB No. 30's requirement that companies report
discontinued operations separately from continuing operations.
All provisions of this Statement will be effective in the first
quarter of 2002. The Company anticipates that the impact of this
new standard will have an immaterial impact on the financial
statements taken as a whole.
Reclassifications
Certain reclassifications have been made to the 2000 and
1999 financial statements to conform with the 2001 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
$6.4 million and $2.3 million at December 31, 2001 and 2000,
respectively, are stated at cost, which approximates market.
The Company's short-term investments available for sale at
December 31, 2001 and 2000 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, 2001, 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.
In 2001, the Company established an oil price hedge on 3,000
Bbl/day for a one-year period beginning on June 1; and a natural
gas price hedge on 5,000 Mmbtu/day for a three-year period
beginning on August 1. Both of these hedges were with Enron as
the counterparty. On December 10, 2001, after Enron filed for
bankruptcy, the Company elected to terminate all contracts with
Enron and agreed with them as to the value of the contracts as of
termination. Based on the agreed value, the Company recorded a
liability of $1.3 million which will be remitted upon the
approval by the Enron bankruptcy judge.
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 2000 and 1999, with
the most recent contracts expiring on December 31, 2000. The
Company recorded losses of $7.1 million and $2.6 million in 2000
and 1999, respectively, which were reported in "Sales of oil and
gas" in the Company's financial statements.
31
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
3. Fair Value of Financial Instruments (cont'd)
In December 2000, the Company entered into a series of
derivative contracts to reduce exposure to unfavorable changes in
natural gas prices. These contracts limited the price the Company
paid for 4,500 Mmbtu/day of natural gas for the three-month
period ending March 31, 2001. In the first quarter of 2001, the
Company earned $1.4 million pre-tax from these hedges which was
recorded as a reduction to "Operating costs - electricity
generation".
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. 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 sales
agreement, beginning in April 2000, with a major California
refiner whereby the Company sells in excess of 80% 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.
For the three years ended December 31, 2001, the Company has
experienced no credit losses on the sale of oil, gas and natural
gas liquids. However, the Company did experience a loss on its
electricity sales in 2001. The Company assigned all of its
rights, title and interest in its $12.1 million past due
receivables from Pacific Gas and Electric Company to an unrelated
party for $9.3 million, resulting in a pre-tax loss of $2.8
million. In addition, at December 31, 2001, the Company was owed
$13.5 million from Southern California Edison Company (SCE) for
past due electricity sales. The Company wrote off $3.6 million
of this balance in March 2001. However, see Note 14.
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, 2001, the Company has not incurred losses
related to these investments.
The following summarizes the accounts receivable balances at
December 31, 2001 and 2000 and sales activity with significant
customers for each of the years ended December 31, 2001, 2000 and
1999 (in thousands). The Company does not believe that the loss
of any one customer would impact the marketability of its oil,
gas, natural gas liquids or electricity sold.
Accounts Receivable Sales
December 31, December 31, For the Year Ended December,31
Customer 2001 2000 2001 2000 1999
Oil & Gas Sales:
A $ 4,754 $ 9,699 $ 83,336 $ 87,613 $ 30,289
B 870 1,246 14,962 18,000 6,262
C 260 391 4,858 5,499 7,890
D 5 24 157 12,390 15,064
E - - - 13,080 11,467
------- ------- ------- ------- -------
$ 5,889 $ 11,360 $ 103,313 $ 136,582 $ 70,972
======= ======= ======= ======= =======
Electricity
Sales:
F $ 9,873 $ 5,625 $ 21,257 $ 23,124 $ 16,013
G - 8,660 6,859 26,769 15,603
H 812 - 6,279 - -
------- ------- ------- ------- -------
$ 10,685 $ 14,285 $ 34,395 $ 49,893 $ 31,616
======= ======= ======= ======= =======
32
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):
2001 2000
Oil and gas:
Proved properties:
Producing properties, including
intangible drilling costs $ 168,930 $ 160,484
Lease and well equipment 146,393 138,007
-------- --------
315,323 298,491
Less accumulated depreciation,
depletion and amortization 113,617 98,925
-------- --------
201,706 199,566
-------- --------
Commercial and other:
Land 173 173
Buildings and improvements 4,086 4,086
Machinery and equipment 3,634 4,553
-------- --------
7,893 8,812
Less accumulated depreciation 6,186 6,735
-------- --------
1,707 2,077
-------- --------
$ 203,413 $ 201,643
======== ========
The following sets forth costs incurred for oil and gas property
acquisition and development activities, whether capitalized or
expensed (in thousands):
2001 2000 1999
Acquisition of
properties/facilities(1) $ 2,273 $ 3,204 $ 34,167
Development 15,875 26,145 9,195
------- ------- -------
$ 18,148 $ 29,349 $ 43,362
======= ======= =======
(1) Includes cogeneration facility costs and certain
closing and consultant costs related to the
acquisitions, but excluding electricity contract
costs.
The Company acquired a 15.8% working interest in coalbed
methane gas properties in Wyoming for $2.2 million and a
producing property adjacent to Berry's core Midway-Sunset
properties for $.1 million during the current year.
Approximately .5 million equivalent barrels of proved reserves
were added by these acquisition. The 2000 acquisition included
the Castruccio property at the Company's Placerita area which
included 1.5 million barrels of reserves and the 1999 acquisition
included the Placerita field acquisition for $35 million which
added approximately 20 million barrels to the Company's reserve
inventory.
33
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):
2001 2000 1999
Sales to unaffiliated parties $100,146 $118,801 $ 66,615
Production costs (40,281) (46,789) (28,697)
Depreciation, depletion and
amortization (16,175) (13,712) (12,020)
------- ------- -------
43,690 58,300 25,898
Income tax expenses (10,740) (15,668) (5,856)
------- ------- -------
Results of operations from
producing and
exploration activities $ 32,950 $ 42,632 $ 20,042
======= ======= =======
6. Debt Obligations
2001 2000 1999
Long-term debt for the years ended
December 31 (in thousands):
Revolving bank facility $ 25,000 $ 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, 2001 and 2000, the
Company had $25 and $25 million, respectively, outstanding under
the Agreement. In addition to the $25 million in borrowings
under the Agreement, the Company has $6.7 million of outstanding
Letters of Credit and the remaining credit available under the
Agreement is therefore, $118.3 million at December 31, 2001. 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, 2001 was 4.92%. 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.
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.
34
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 replaced 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.
In August 2001, the Board of Directors authorized the
Company to repurchase $20 million of Common Stock in the open
market. As of December 31, 2001, the Company had repurchased
308,075 shares for approximately $5.1 million. All shares
repurchased were retired.
The Company issued 6,529, 21,325 and 2,745 shares in 2001,
2000 and 1999, respectively, through its stock option plan.
At December 31, 2001, 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):
2001 2000 1999
Current:
Federal $ 3,108 $ 10,336 $ 2,661
State 1,119 3,165 928
------- ------- -------
4,227 13,501 3,589
------- ------- -------
Deferred:
Federal 1,755 1,787 1,979
State (682) (795) (663)
------- ------- -------
1,073 992 1,316
------- ------- -------
Total $ 5,300 $ 14,493 $ 4,905
======= ======= =======
35
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):
2001 2000 1999
Deferred tax asset
Federal benefit of state taxes
taxes $ 392 $ 871 $ 392
Credit/deduction
carryforwards 11,599 7,761 4,434
Other, net 579 1,261 367
------- ------- -------
12,570 9,893 5,193
------- ------- -------
Deferred tax liability
Depreciation and depletion (43,608) (39,894) (33,452)
Other, net 210 246 (504)
------- ------- -------
(43,398) (39,648) (33,956)
------- ------- -------
Net deferred tax liability $(30,828) $(29,755) $(28,763)
======= ======= =======
Reconciliation of the statutory federal income tax rate to the
effective income tax rate follows:
2001 2000 1999
Tax computed at statutory federal
rate 35.0% 35.0% 35.0%
State income taxes, net of
federal benefit 1.0 2.3 .3
Tax credits (15.7) (11.0) (12.9)
Other (.8) 1.8 (1.0)
------ ------ ------
Effective tax rate 19.5% 28.1% 21.4%
====== ====== ======
The Company has approximately $9.0 million of federal and
$5.8 million of state (California) enhanced oil recovery (EOR)
tax credit carryforwards available to reduce future income taxes.
Total EOR credits of $.2 million, $1.1 million, $6.2 million and
$7.3 million will expire in 2013, 2014, 2015 and 2016,
respectively.
36
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Commitment
Corporate Offices Operating Lease
The Company relocated its corporate offices in March 2002.
The lease term is from January 1, 2002 through October 31, 2006
and requires minimum rental payments as follows:
Year ending
December 31,
2002 $ 366,920
2003 440,305
2004 440,305
2005 440,305
2006 366,920
---------
Total $2,054,755
=========
10. Contingencies
The Company has accrued environmental liabilities for all
sites, including sites in which governmental agencies have
designated the Company as a potentially responsible party (PRP),
where it is probable that a loss will be incurred and the minimum
cost or amount of loss can be reasonably estimated. However,
because of the uncertainties associated with environmental
assessment and remediation activities, future expense to
remediate the currently identified sites, and sites which could
be identified in the future for cleanup, could be higher than the
liability currently accrued. Amounts currently accrued are not
significant to the consolidated financial position of the Company
and Management believes, based upon current site assessments,
that the ultimate resolution of these matters will not require
substantial additional accruals.
The Company is involved in various other lawsuits, claims
and inquiries, most of which are routine to the nature of its
business. In the opinion of Management, the resolution of these
matters will not materially affect the Company.
11. 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 7, 2001 and December 1, 2000, 199,500 and
262,000 options, respectively, were issued to certain key
employees at an exercise price of $16.30 and $15.6875 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 40,000
options, respectively, were issued on December 2, 2001, 2000 and
1999, (5,000 options to each of the non-employee Directors each
year) at an exercise price of $15.45, $15.6875 and $14.0625 per
share, respectively.
37
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
11. Stock Option Plan (cont'd)
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 $0 million in 2001, $.3
million in 2000 and $0 in 1999.
Under SFAS No. 123, compensation cost would be recognized
for the fair value of the employee's option rights. The fair
value of each option grant was estimated on the date of grant
using the Black-Scholes option-pricing model with the following
assumptions:
2001 2000 1999
Yield 2.72% 2.77% 2.75%
Expected option life - years 7.5 4.5 4.0
Volatility 38.71% 36.53% 34.24%
Risk-free interest rate 4.65% 4.85% 6.33%
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):
2001 2000 1999
Net income as reported $21,938 $37,183 $18,006
Pro forma 21,197 36,581 17,343
Net income per share as reported 1.00 1.69 .82
Pro forma .99 1.66 .79
The following is a summary of stock-based compensation
activity for the years 2001, 2000 and 1999.
2001 2000 1999
Options Options Options
Balance outstanding, January 1 1,407,837 1,220,630 1,227,630
Granted 239,500 302,000 40,000
Exercised (65,125) (114,793) (22,000)
Canceled/expired (107,250) - (25,000)
--------- --------- ---------
Balance outstanding, December 31 1,474,962 1,407,837 1,220,630
========= ========= =========
Balance exercisable at
December 31 1,010,712 872,587 697,630
========= ========= =========
Available for future grant 232,550 364,800 666,800
========= ========= =========
Exercise price-range $ 14.40 $ 16.4375 $ 14.125
to 16.96 to 19.00 to 14.25
Weighted average remaining
contractual life (years) 7 8 8
Weighted average fair value
per option granted during the $ 5.87 $ 4.62 $ 5.14
year
38
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
11. Stock Option Plan (cont'd)
Weighted average option exercise price information for the
years 2001, 2000 and 1999 as follows:
2001 2000 1999
Outstanding at January 1 $ 14.58 $ 14.15 $ 14.18
Granted during the year 16.16 15.69 14.06
Exercised during the year 13.12 12.91 12.40
Expired during the year 16.01 - 16.69
Outstanding at December 31 14.80 14.58 14.15
Exercisable at December 31 14.55 14.50 14.21
12. 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 $.4 million
in 2001, $.5 million in 2000 and $.3 million in 1999.
13. Quarterly Financial Data (unaudited)
The following is a tabulation of unaudited quarterly
operating results for 2001 and 2000 (in thousands, except per
share data):
Basic net Diluted net
Operating Gross Net Income Income
2001 Revenues Profit Income Per Share Per Share
First Quarter $ 47,915 $ 15,365 $ 5,022 $ .23 $ .23
Second Quarter 29,047 12,755 6,975 .32 .32
Third Quarter 31,995 8,900 5,892 .27 .27
Fourth Quarter 27,108 5,210 4,049 .19 .18
------- ------- ------- ----- -----
$136,065 $ 42,230 $ 21,938 $1.00 $ .99
======= ======= ======= ===== =====
2000
First Quarter $ 35,136 $ 14,525 $ 8,859 $ .40 $ .40
Second Quarter 36,446 14,187 8,894 .40 .40
Third Quarter 45,939 15,096 9,578 .43 .43
Fourth Quarter 54,045 16,450 9,852 .45 .44
------- ------- ------- ----- -----
$171,566 $ 60,258 $ 37,183 $1.69 $1.67
======= ======= ======= ===== =====
14. Subsequent Events
At December 31, 2001, the Company was owed $13.5 million by
Edison for past due electricity sales. Of this amount, $9.3
million was recorded as a receivable. On March 1, 2002, the
Company was paid the total amount due the Company of $13.5
million plus interest. The Company will record $4.2 million in
pre-tax income in the first quarter of 2002 due to this
collection.
39
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, 2001, 2000 and 1999. 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, 2001, 2000 and 1999, and changes in such quantities during
each of the years then ended were as follows (in thousands):
2001 2000 1999
Oil Gas Oil Gas Oil Gas
Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf
Proved developed and
undeveloped reserves:
Beginning of year 106,664 4,184 111,888 3,920 91,933 4,060
Revision of previous
estimates 33 153 (1,284) 463 3,126 40
Production (4,996) (288) (5,434) (199) (5,060) (180)
Purchase of reserves
in place - 2,877 1,494 - 21,889 -
------- ----- ------- ----- ------- -----
End of year 101,701 6,926 106,664 4,184 111,888 3,920
======= ===== ======= ===== ======= =====
Proved developed
reserves:
Beginning of year 81,132 1,635 86,717 1,371 83,532 1,604
======= ===== ======= ===== ======= =====
End of year 79,317 3,518 81,132 1,635 86,717 1,371
======= ===== ======= ===== ======= =====
40
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):
2001 2000 1999
Future cash inflows $1,452,946 $2,268,932 $2,208,964
Future production and development
costs (699,505) (653,808) (647,720)
Future income tax expenses (184,064) (512,012) (502,951)
--------- --------- ---------
Future net cash flows 569,377 1,103,112 1,058,293
10% annual discount for estimated
timing of cash flows (289,036) (599,530) (561,811)
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 280,341 $ 503,582 $ 496,482
========= ========= =========
Pre-tax standardized measure of $ 356,556 $ 721,770 $ 714,555
discounted future net cash flows ========= ========= =========
Average sales prices at December 31:
Oil ($/Bbl) $ 14.18 $ 20.63 $ 19.41
Gas ($/Mcf) $ 1.98 $ 10.94 $ 2.11
Changes in standardized measure of discounted future net cash
flows from proved oil and gas reserves (in thousands):
2001 2000 1999
Standardized measure - beginning
of year $ 503,582 $ 496,482 $ 106,517
-------- -------- --------
Sales of oil and gas produced, net of
of production costs (59,865) (72,358) (44,587)
Revisions to estimates of proved
reserves:
Net changes in sales prices and
production costs (407,519) 98,744 440,729
Revisions of previous quantity
estimates 230 (9,295) 20,919
Change in estimated future
development costs 48,689 (78,328) (24,709)
Purchases of reserves in place 2,606 14,135 169,147
Development costs incurred during
the period 14,895 25,253 9,122
Accretion of discount 72,177 71,455 11,381
Income taxes 135,792 (3,929) (203,514)
Other (30,246) (38,577) 11,477
-------- -------- --------
Net increase (decrease) (223,241) 7,100 389,965
-------- -------- --------
Standardized measure - end of year $ 280,341 $ 503,582 $ 496,482
======== ======== ========
41
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.
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.
42
BERRY PETROLEUM COMPANY
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K (cont'd)
B. Reports on Form 8-K
None
C.
Exhibits
Exhibit Description of Exhibit Page
No.
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 46
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
(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)
43
Exhibits (cont'd)
Exhibit Description of Exhibit
No. Page
10.8* 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 47
23.2 Consent of DeGolyer and MacNaughton 48
99.1 Undertaking for Form S-8 Registration Statements 49
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
44
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 1, 2002.
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 Controller
Director, President and Chief Financial (Principal
and Chief Executive Officer Accounting Officer)
Officer (Principal Financial
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, March 1, 2002
Jerry V. Hoffman Director, President & Chief
Executive Officer
/s/ William F. Berry Director March 1, 2002
William F. Berry
/s/ Ralph B. Busch, III Director March 1, 2002
Ralph B. Busch, III
/s/ William E. Bush, Jr. Director March 1, 2002
William E. Bush, Jr.
/s/ J. Herbert Gaul, Jr. Director March 1, 2002
J. Herbert Gaul, Jr.
/s/ John A. Hagg Director March 1, 2002
John A. Hagg
/s/ Thomas J. Jamieson Director March 1, 2002
Thomas J. Jamieson
/s/ Roger G. Martin Director March 1, 2002
Roger G. Martin
/s/ Martin H. Young, Jr. Director March 1, 2002
Martin H. Young, Jr.
45